0001021635000007414512/3110-K2020FYFALSE200,021,1616,077,156,2822.62.7P2Y00010216352020-01-012020-12-310001021635oge:OgAndEMember2020-01-012020-12-31xbrli:shares00010216352020-12-31iso4217:USD00010216352020-06-30iso4217:USDxbrli:shares0001021635oge:OgAndEMember2020-12-3100010216352019-01-012019-12-3100010216352018-01-012018-12-310001021635oge:PensionPlansMember2020-01-012020-12-310001021635oge:PensionPlansMember2019-01-012019-12-310001021635oge:PensionPlansMember2018-01-012018-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-01-012020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-01-012019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2018-01-012018-12-3100010216352019-12-3100010216352018-12-3100010216352017-12-31xbrli:pure0001021635oge:SeriesDueJuly152027Memberus-gaap:SeniorNotesMemberoge:OgAndEMember2020-12-310001021635oge:SeriesDueJuly152027Memberus-gaap:SeniorNotesMemberoge:OgAndEMember2020-01-012020-12-310001021635oge:SeriesDueJuly152027Memberus-gaap:SeniorNotesMemberoge:OgAndEMember2019-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueApril152028Member2020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueApril152028Member2020-01-012020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueApril152028Member2019-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueAugust152028MemberMember2020-12-310001021635us-gaap:SeniorNotesMemberoge:SeriesdueAugust152028Memberoge:OgAndEMember2020-01-012020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueAugust152028MemberMember2019-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueMarch152030Member2020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueMarch152030Member2020-01-012020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueMarch152030Member2019-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueApril12030Member2020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueApril12030Member2020-01-012020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueApril12030Member2019-12-310001021635oge:SeriesDueJanuary152036Memberus-gaap:SeniorNotesMemberoge:OgAndEMember2020-12-310001021635oge:SeriesDueJanuary152036Memberus-gaap:SeniorNotesMemberoge:OgAndEMember2020-01-012020-12-310001021635oge:SeriesDueJanuary152036Memberus-gaap:SeniorNotesMemberoge:OgAndEMember2019-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueFebruary12038Member2020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueFebruary12038Member2020-01-012020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueFebruary12038Member2019-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueJune12040Member2020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueJune12040Member2020-01-012020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueJune12040Member2019-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeniorNotesDueMay152041Member2020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeniorNotesDueMay152041Member2020-01-012020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeniorNotesDueMay152041Member2019-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueMay12043Member2020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueMay12043Member2020-01-012020-12-310001021635us-gaap:SeniorNotesMemberoge:OgAndEMemberoge:SeriesDueMay12043Member2019-12-310001021635us-gaap:SeniorNotesMemberoge:SeriesdueMarch152044Memberoge:OgAndEMember2020-12-310001021635us-gaap:SeniorNotesMemberoge:SeriesdueMarch152044Memberoge:OgAndEMember2020-01-012020-12-310001021635us-gaap:SeniorNotesMemberoge:SeriesdueMarch152044Memberoge:OgAndEMember2019-12-310001021635oge:SeriesdueDecember152044Memberus-gaap:SeniorNotesMemberoge:OgAndEMember2020-12-310001021635oge:SeriesdueDecember152044Memberus-gaap:SeniorNotesMemberoge:OgAndEMember2020-01-012020-12-310001021635oge:SeriesdueDecember152044Memberus-gaap:SeniorNotesMemberoge:OgAndEMember2019-12-310001021635oge:SeriesdueApril12047Memberus-gaap:SeniorNotesMemberoge:OgAndEMember2020-12-310001021635oge:SeriesdueApril12047Memberus-gaap:SeniorNotesMemberoge:OgAndEMember2020-01-012020-12-310001021635oge:SeriesdueApril12047Memberus-gaap:SeniorNotesMemberoge:OgAndEMember2019-12-310001021635oge:SeriesdueAugust152047MemberDomainus-gaap:SeniorNotesMemberoge:OgAndEMember2020-12-310001021635oge:SeriesdueAugust152047MemberDomainus-gaap:SeniorNotesMemberoge:OgAndEMember2020-01-012020-12-310001021635oge:SeriesdueAugust152047MemberDomainus-gaap:SeniorNotesMemberoge:OgAndEMember2019-12-310001021635oge:OgAndEMemberus-gaap:LongTermDebtMemberoge:DueAugust312062Member2020-12-310001021635oge:OgAndEMemberus-gaap:LongTermDebtMemberoge:DueAugust312062Member2020-01-012020-12-310001021635oge:OgAndEMemberus-gaap:LongTermDebtMemberoge:DueAugust312062Member2019-12-310001021635us-gaap:DebenturesSubjectToMandatoryRedemptionMemberoge:GarfieldIndustrialAuthorityBondMembersrt:MinimumMember2020-12-310001021635us-gaap:DebenturesSubjectToMandatoryRedemptionMembersrt:MaximumMemberoge:GarfieldIndustrialAuthorityBondMember2020-12-310001021635oge:GarfieldIndustrialAuthorityBondMember2020-01-012020-12-310001021635us-gaap:DebenturesSubjectToMandatoryRedemptionMemberoge:OgAndEMemberoge:GarfieldIndustrialAuthorityBondMember2020-12-310001021635us-gaap:DebenturesSubjectToMandatoryRedemptionMemberoge:OgAndEMemberoge:GarfieldIndustrialAuthorityBondMember2019-12-310001021635us-gaap:DebenturesSubjectToMandatoryRedemptionMemberoge:MuskogeeIndustrialAuthorityBondDue2025Membersrt:MinimumMember2020-12-310001021635us-gaap:DebenturesSubjectToMandatoryRedemptionMembersrt:MaximumMemberoge:MuskogeeIndustrialAuthorityBondDue2025Member2020-12-310001021635oge:MuskogeeIndustrialAuthorityBondDue2025Member2020-01-012020-12-310001021635us-gaap:DebenturesSubjectToMandatoryRedemptionMemberoge:OgAndEMemberoge:MuskogeeIndustrialAuthorityBondDue2025Member2020-12-310001021635us-gaap:DebenturesSubjectToMandatoryRedemptionMemberoge:OgAndEMemberoge:MuskogeeIndustrialAuthorityBondDue2025Member2019-12-310001021635oge:MuskogeeIndustrialAuthorityBondDue2027Memberus-gaap:DebenturesSubjectToMandatoryRedemptionMembersrt:MinimumMember2020-12-310001021635oge:MuskogeeIndustrialAuthorityBondDue2027Memberus-gaap:DebenturesSubjectToMandatoryRedemptionMembersrt:MaximumMember2020-12-310001021635oge:MuskogeeIndustrialAuthorityBondDue2027Member2020-01-012020-12-310001021635oge:MuskogeeIndustrialAuthorityBondDue2027Memberus-gaap:DebenturesSubjectToMandatoryRedemptionMemberoge:OgAndEMember2020-12-310001021635oge:MuskogeeIndustrialAuthorityBondDue2027Memberus-gaap:DebenturesSubjectToMandatoryRedemptionMemberoge:OgAndEMember2019-12-310001021635oge:OgAndEMember2019-12-310001021635us-gaap:CommonStockMember2017-12-310001021635us-gaap:TreasuryStockMember2017-12-310001021635us-gaap:AdditionalPaidInCapitalMember2017-12-310001021635us-gaap:RetainedEarningsMember2017-12-310001021635us-gaap:AccumulatedOtherComprehensiveIncomeMember2017-12-310001021635us-gaap:CommonStockMember2018-01-012018-12-310001021635us-gaap:TreasuryStockMember2018-01-012018-12-310001021635us-gaap:AdditionalPaidInCapitalMember2018-01-012018-12-310001021635us-gaap:RetainedEarningsMember2018-01-012018-12-310001021635us-gaap:AccumulatedOtherComprehensiveIncomeMember2018-01-012018-12-310001021635us-gaap:CommonStockMember2018-12-310001021635us-gaap:TreasuryStockMember2018-12-310001021635us-gaap:AdditionalPaidInCapitalMember2018-12-310001021635us-gaap:RetainedEarningsMember2018-12-310001021635us-gaap:AccumulatedOtherComprehensiveIncomeMember2018-12-310001021635us-gaap:CommonStockMember2019-01-012019-12-310001021635us-gaap:TreasuryStockMember2019-01-012019-12-310001021635us-gaap:AdditionalPaidInCapitalMember2019-01-012019-12-310001021635us-gaap:RetainedEarningsMember2019-01-012019-12-310001021635us-gaap:AccumulatedOtherComprehensiveIncomeMember2019-01-012019-12-310001021635us-gaap:CommonStockMember2019-12-310001021635us-gaap:TreasuryStockMember2019-12-310001021635us-gaap:AdditionalPaidInCapitalMember2019-12-310001021635us-gaap:RetainedEarningsMember2019-12-310001021635us-gaap:AccumulatedOtherComprehensiveIncomeMember2019-12-310001021635us-gaap:CommonStockMember2020-01-012020-12-310001021635us-gaap:TreasuryStockMember2020-01-012020-12-310001021635us-gaap:AdditionalPaidInCapitalMember2020-01-012020-12-310001021635us-gaap:RetainedEarningsMember2020-01-012020-12-310001021635us-gaap:AccumulatedOtherComprehensiveIncomeMember2020-01-012020-12-3100010216352020-01-012020-09-300001021635us-gaap:CommonStockMember2020-12-310001021635us-gaap:TreasuryStockMember2020-12-310001021635us-gaap:AdditionalPaidInCapitalMember2020-12-310001021635us-gaap:RetainedEarningsMember2020-12-310001021635us-gaap:AccumulatedOtherComprehensiveIncomeMember2020-12-310001021635oge:OgAndEMember2019-01-012019-12-310001021635oge:OgAndEMember2018-01-012018-12-310001021635oge:OgAndEMember2018-12-310001021635oge:OgAndEMember2017-12-310001021635oge:OgAndEMember2020-09-300001021635oge:OgAndEMemberus-gaap:CommonStockMember2017-12-310001021635oge:OgAndEMemberus-gaap:AdditionalPaidInCapitalMember2017-12-310001021635us-gaap:RetainedEarningsMemberoge:OgAndEMember2017-12-310001021635oge:OgAndEMemberus-gaap:CommonStockMember2018-01-012018-12-310001021635oge:OgAndEMemberus-gaap:AdditionalPaidInCapitalMember2018-01-012018-12-310001021635us-gaap:RetainedEarningsMemberoge:OgAndEMember2018-01-012018-12-310001021635oge:OgAndEMemberus-gaap:CommonStockMember2018-12-310001021635oge:OgAndEMemberus-gaap:AdditionalPaidInCapitalMember2018-12-310001021635us-gaap:RetainedEarningsMemberoge:OgAndEMember2018-12-310001021635oge:OgAndEMemberus-gaap:CommonStockMember2019-01-012019-12-310001021635oge:OgAndEMemberus-gaap:AdditionalPaidInCapitalMember2019-01-012019-12-310001021635us-gaap:RetainedEarningsMemberoge:OgAndEMember2019-01-012019-12-310001021635oge:OgAndEMemberus-gaap:CommonStockMember2019-12-310001021635oge:OgAndEMemberus-gaap:AdditionalPaidInCapitalMember2019-12-310001021635us-gaap:RetainedEarningsMemberoge:OgAndEMember2019-12-310001021635oge:OgAndEMemberus-gaap:CommonStockMember2020-01-012020-12-310001021635oge:OgAndEMemberus-gaap:AdditionalPaidInCapitalMember2020-01-012020-12-310001021635us-gaap:RetainedEarningsMemberoge:OgAndEMember2020-01-012020-12-310001021635oge:OgAndEMemberus-gaap:CommonStockMember2020-12-310001021635oge:OgAndEMemberus-gaap:AdditionalPaidInCapitalMember2020-12-310001021635us-gaap:RetainedEarningsMemberoge:OgAndEMember2020-12-310001021635oge:CenterpointMember2020-12-310001021635oge:OgeEnergyMember2020-12-310001021635oge:SPPCostTrackerRiderUnderRecoveryMember2020-12-310001021635oge:SPPCostTrackerRiderUnderRecoveryMember2019-12-310001021635oge:GenerationCapacityReplacementRiderMember2020-12-310001021635oge:GenerationCapacityReplacementRiderMember2019-12-310001021635oge:OtherRegulatoryAssetsMember2020-12-310001021635oge:OtherRegulatoryAssetsMember2019-12-310001021635oge:BenefitObligationsMember2020-12-310001021635oge:BenefitObligationsMember2019-12-310001021635oge:DeferredStormExpensesMember2020-12-310001021635oge:DeferredStormExpensesMember2019-12-310001021635oge:DryScrubberRegulatoryAssetMember2020-12-310001021635oge:DryScrubberRegulatoryAssetMember2019-12-310001021635oge:PensionTrackerMember2020-12-310001021635oge:PensionTrackerMember2019-12-310001021635oge:SmartGridMember2020-12-310001021635oge:SmartGridMember2019-12-310001021635us-gaap:LossOnReacquiredDebtMember2020-12-310001021635us-gaap:LossOnReacquiredDebtMember2019-12-310001021635oge:DeferredPensionExpensesMember2020-12-310001021635oge:DeferredPensionExpensesMember2019-12-310001021635oge:FrontierPlantMember2020-12-310001021635oge:FrontierPlantMember2019-12-310001021635oge:COVID19ImpactMember2020-12-310001021635oge:COVID19ImpactMember2019-12-310001021635oge:OklahomaDemandProgramRiderOverRecoveryMember2020-12-310001021635oge:OklahomaDemandProgramRiderOverRecoveryMember2019-12-310001021635oge:ReserveforTaxRefundMember2020-12-310001021635oge:ReserveforTaxRefundMember2019-12-310001021635oge:SPPCostTrackerRiderOverRecoveryMember2020-12-310001021635oge:SPPCostTrackerRiderOverRecoveryMember2019-12-310001021635oge:OtherRegulatoryLiabilitiesMember2020-12-310001021635oge:OtherRegulatoryLiabilitiesMember2019-12-310001021635oge:IncomeTaxesRecoverableFromCustomersNetMember2020-12-310001021635oge:IncomeTaxesRecoverableFromCustomersNetMember2019-12-310001021635oge:AccruedRemovalObligationsMember2020-12-310001021635oge:AccruedRemovalObligationsMember2019-12-310001021635us-gaap:PensionPlansDefinedBenefitMemberoge:DefinedBenefitPlansIncomeLossMember2020-12-310001021635us-gaap:PensionPlansDefinedBenefitMemberoge:DefinedBenefitPlansIncomeLossMember2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:DefinedBenefitPlansIncomeLossMember2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:DefinedBenefitPlansIncomeLossMember2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:PriorServiceCostMember2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:PriorServiceCostMember2019-12-310001021635us-gaap:PublicUtilitiesInventoryFuelMember2020-12-310001021635us-gaap:PublicUtilitiesInventoryFuelMember2019-12-310001021635oge:McclainPlantMember2020-12-310001021635oge:RedbudPlantMember2020-12-310001021635oge:McclainPlantMember2019-12-310001021635oge:RedbudPlantMember2019-12-310001021635oge:OgAndEMemberus-gaap:ElectricDistributionMember2020-12-310001021635oge:OgAndEMemberus-gaap:ElectricGenerationEquipmentMember2020-12-310001021635oge:OgAndEMemberus-gaap:ElectricTransmissionMember2020-12-310001021635oge:OgAndEMemberoge:FiniteLivedIntangibleAssetsMajorClassNameMember2020-12-310001021635us-gaap:PropertyPlantAndEquipmentOtherTypesMemberoge:OgAndEMember2020-12-310001021635oge:OgAndEMemberoge:TotalPropertyPlantAndEquipmentMember2020-12-310001021635oge:OgAndEMemberus-gaap:ElectricDistributionMember2019-12-310001021635oge:OgAndEMemberus-gaap:ElectricGenerationEquipmentMember2019-12-310001021635oge:OgAndEMemberus-gaap:ElectricTransmissionMember2019-12-310001021635oge:OgAndEMemberoge:FiniteLivedIntangibleAssetsMajorClassNameMember2019-12-310001021635us-gaap:PropertyPlantAndEquipmentOtherTypesMemberoge:OgAndEMember2019-12-310001021635oge:OgAndEMemberoge:TotalPropertyPlantAndEquipmentMember2019-12-310001021635oge:OgeEnergyMember2019-12-310001021635oge:OgAndEMemberoge:TransmissionEquipmentMember2020-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberus-gaap:PensionPlansDefinedBenefitMember2018-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2018-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceCostCreditMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2018-12-310001021635us-gaap:CommodityContractMember2018-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberus-gaap:PensionPlansDefinedBenefitMember2019-01-012019-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-01-012019-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceCostCreditMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-01-012019-12-310001021635us-gaap:CommodityContractMember2019-01-012019-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceCostCreditMemberoge:SettlementCostMemberus-gaap:PensionPlansDefinedBenefitMember2019-01-012019-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberoge:SettlementCostMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-01-012019-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceCostCreditMemberoge:SettlementCostMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-01-012019-12-310001021635oge:SettlementCostMemberus-gaap:CommodityContractMember2019-01-012019-12-310001021635oge:SettlementCostMember2019-01-012019-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceCostCreditMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310001021635us-gaap:CommodityContractMember2019-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberus-gaap:PensionPlansDefinedBenefitMember2020-01-012020-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-01-012020-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceCostCreditMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-01-012020-12-310001021635us-gaap:CommodityContractMember2020-01-012020-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberoge:CurtailmentMemberus-gaap:PensionPlansDefinedBenefitMember2020-01-012020-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberoge:CurtailmentMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-01-012020-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceCostCreditMemberoge:CurtailmentMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-01-012020-12-310001021635oge:CurtailmentMemberus-gaap:CommodityContractMember2020-01-012020-12-310001021635oge:CurtailmentMember2020-01-012020-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceCostCreditMemberoge:SettlementCostMemberus-gaap:PensionPlansDefinedBenefitMember2020-01-012020-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberoge:SettlementCostMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-01-012020-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceCostCreditMemberoge:SettlementCostMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-01-012020-12-310001021635oge:SettlementCostMemberus-gaap:CommodityContractMember2020-01-012020-12-310001021635oge:SettlementCostMember2020-01-012020-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310001021635us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceCostCreditMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310001021635us-gaap:CommodityContractMember2020-12-310001021635us-gaap:PensionPlansDefinedBenefitMember2020-01-012020-12-310001021635us-gaap:PensionPlansDefinedBenefitMember2019-01-012019-12-310001021635oge:ResidentialMember2020-01-012020-12-310001021635oge:ResidentialMember2019-01-012019-12-310001021635oge:ResidentialMember2018-01-012018-12-310001021635oge:CommercialMember2020-01-012020-12-310001021635oge:CommercialMember2019-01-012019-12-310001021635oge:CommercialMember2018-01-012018-12-310001021635oge:IndustrialMember2020-01-012020-12-310001021635oge:IndustrialMember2019-01-012019-12-310001021635oge:IndustrialMember2018-01-012018-12-310001021635oge:OilfieldMember2020-01-012020-12-310001021635oge:OilfieldMember2019-01-012019-12-310001021635oge:OilfieldMember2018-01-012018-12-310001021635oge:PublicAuthorityMember2020-01-012020-12-310001021635oge:PublicAuthorityMember2019-01-012019-12-310001021635oge:PublicAuthorityMember2018-01-012018-12-310001021635oge:TotalRetailCustomerMember2020-01-012020-12-310001021635oge:TotalRetailCustomerMember2019-01-012019-12-310001021635oge:TotalRetailCustomerMember2018-01-012018-12-310001021635oge:ProvisionforRateRefundMember2020-01-012020-12-310001021635oge:ProvisionforRateRefundMember2019-01-012019-12-310001021635oge:ProvisionforRateRefundMember2018-01-012018-12-310001021635oge:IntegratedMarketMember2020-01-012020-12-310001021635oge:IntegratedMarketMember2019-01-012019-12-310001021635oge:IntegratedMarketMember2018-01-012018-12-310001021635oge:TransmissionMember2020-01-012020-12-310001021635oge:TransmissionMember2019-01-012019-12-310001021635oge:TransmissionMember2018-01-012018-12-310001021635oge:OtherContractswithCustomersMember2020-01-012020-12-310001021635oge:OtherContractswithCustomersMember2019-01-012019-12-310001021635oge:OtherContractswithCustomersMember2018-01-012018-12-310001021635oge:EnogexLlcMember2013-05-010001021635oge:OgeHoldingsMember2020-01-012020-12-310001021635oge:EnableMidstreamPartnersMember2020-12-310001021635us-gaap:EquityMethodInvestmentNonconsolidatedInvesteeOrGroupOfInvesteesMember2020-12-310001021635us-gaap:EquityMethodInvestmentNonconsolidatedInvesteeOrGroupOfInvesteesMember2019-12-310001021635us-gaap:EquityMethodInvestmentNonconsolidatedInvesteeOrGroupOfInvesteesMember2020-01-012020-12-310001021635us-gaap:EquityMethodInvestmentNonconsolidatedInvesteeOrGroupOfInvesteesMember2019-01-012019-12-310001021635us-gaap:EquityMethodInvestmentNonconsolidatedInvesteeOrGroupOfInvesteesMember2018-01-012018-12-310001021635oge:OgeEnergyMember2020-01-012020-12-310001021635oge:EnableMidstreamPartnersMember2020-01-012020-12-310001021635oge:EnableMidstreamPartnersMember2019-01-012019-12-310001021635oge:EnableMidstreamPartnersMember2018-01-012018-12-310001021635oge:EnergyTransferMember2020-01-012020-12-310001021635oge:OgAndEMemberoge:OgeEnergyMember2020-01-012020-12-310001021635oge:OgAndEMemberoge:OgeEnergyMember2019-01-012019-12-310001021635oge:OgAndEMemberoge:OgeEnergyMember2018-01-012018-12-310001021635oge:EnableMidstreamPartnersMemberoge:OperatingCostsChargedMemberoge:OgeEnergyMember2020-01-012020-12-310001021635oge:EnableMidstreamPartnersMemberoge:OperatingCostsChargedMemberoge:OgeEnergyMember2019-01-012019-12-310001021635oge:EnableMidstreamPartnersMemberoge:OperatingCostsChargedMemberoge:OgeEnergyMember2018-01-012018-12-310001021635oge:EnableMidstreamPartnersMemberoge:OgeEnergyMemberoge:EmploymentCostsMember2020-01-012020-12-310001021635oge:EnableMidstreamPartnersMemberoge:OgeEnergyMemberoge:EmploymentCostsMember2019-01-012019-12-310001021635oge:EnableMidstreamPartnersMemberoge:OgeEnergyMemberoge:EmploymentCostsMember2018-01-012018-12-310001021635oge:ExcludingFuelPurchasesMember2020-12-310001021635oge:ExcludingFuelPurchasesMember2019-12-310001021635oge:EnableMidstreamPartnersMemberoge:OgAndEMember2020-01-012020-12-310001021635oge:EnableMidstreamPartnersMemberoge:OgAndEMember2019-01-012019-12-310001021635oge:EnableMidstreamPartnersMemberoge:OgAndEMember2018-01-012018-12-310001021635oge:EnableMidstreamPartnersMemberoge:NaturalGasTransportationMemberoge:OgAndEMember2020-01-012020-12-310001021635oge:EnableMidstreamPartnersMemberoge:NaturalGasTransportationMemberoge:OgAndEMember2019-01-012019-12-310001021635oge:EnableMidstreamPartnersMemberoge:NaturalGasTransportationMemberoge:OgAndEMember2018-01-012018-12-310001021635oge:NaturalGasPurchasesMemberoge:EnableMidstreamPartnersMemberoge:OgAndEMember2020-01-012020-12-310001021635oge:NaturalGasPurchasesMemberoge:EnableMidstreamPartnersMemberoge:OgAndEMember2019-01-012019-12-310001021635oge:NaturalGasPurchasesMemberoge:EnableMidstreamPartnersMemberoge:OgAndEMember2018-01-012018-12-310001021635us-gaap:FairValueMeasurementsRecurringMember2020-12-310001021635us-gaap:FairValueMeasurementsRecurringMember2019-12-310001021635oge:OgAndESeniorNotesMember2020-12-310001021635oge:OgAndESeniorNotesMember2019-12-310001021635oge:OgAndEIndustrialAuthorityBondsMember2020-12-310001021635oge:OgAndEIndustrialAuthorityBondsMember2019-12-310001021635oge:OgAndETinkerDebtMember2020-12-310001021635oge:OgAndETinkerDebtMember2019-12-310001021635us-gaap:PerformanceSharesMemberoge:TotalShareholderReturnMember2020-01-012020-12-310001021635us-gaap:PerformanceSharesMemberoge:TotalShareholderReturnMember2019-01-012019-12-310001021635us-gaap:PerformanceSharesMemberoge:TotalShareholderReturnMember2018-01-012018-12-310001021635oge:OgAndEMemberus-gaap:PerformanceSharesMemberoge:TotalShareholderReturnMember2020-01-012020-12-310001021635oge:OgAndEMemberus-gaap:PerformanceSharesMemberoge:TotalShareholderReturnMember2019-01-012019-12-310001021635oge:OgAndEMemberus-gaap:PerformanceSharesMemberoge:TotalShareholderReturnMember2018-01-012018-12-310001021635oge:PerformanceUnitsRelatedToEarningsPerShareMemberus-gaap:PerformanceSharesMember2020-01-012020-12-310001021635oge:PerformanceUnitsRelatedToEarningsPerShareMemberus-gaap:PerformanceSharesMember2019-01-012019-12-310001021635oge:PerformanceUnitsRelatedToEarningsPerShareMemberus-gaap:PerformanceSharesMember2018-01-012018-12-310001021635oge:PerformanceUnitsRelatedToEarningsPerShareMemberoge:OgAndEMemberus-gaap:PerformanceSharesMember2020-01-012020-12-310001021635oge:PerformanceUnitsRelatedToEarningsPerShareMemberoge:OgAndEMemberus-gaap:PerformanceSharesMember2019-01-012019-12-310001021635oge:PerformanceUnitsRelatedToEarningsPerShareMemberoge:OgAndEMemberus-gaap:PerformanceSharesMember2018-01-012018-12-310001021635us-gaap:PerformanceSharesMember2020-01-012020-12-310001021635us-gaap:PerformanceSharesMember2019-01-012019-12-310001021635us-gaap:PerformanceSharesMember2018-01-012018-12-310001021635oge:OgAndEMemberus-gaap:PerformanceSharesMember2020-01-012020-12-310001021635oge:OgAndEMemberus-gaap:PerformanceSharesMember2019-01-012019-12-310001021635oge:OgAndEMemberus-gaap:PerformanceSharesMember2018-01-012018-12-310001021635us-gaap:RestrictedStockMember2020-01-012020-12-310001021635us-gaap:RestrictedStockMember2019-01-012019-12-310001021635us-gaap:RestrictedStockMember2018-01-012018-12-310001021635us-gaap:RestrictedStockMemberoge:OgAndEMember2020-01-012020-12-310001021635us-gaap:RestrictedStockMemberoge:OgAndEMember2019-01-012019-12-310001021635us-gaap:RestrictedStockMemberoge:OgAndEMember2018-01-012018-12-310001021635us-gaap:StockCompensationPlanMember2020-01-012020-12-310001021635us-gaap:StockCompensationPlanMember2019-01-012019-12-310001021635us-gaap:StockCompensationPlanMember2018-01-012018-12-310001021635oge:OgAndEMemberus-gaap:StockCompensationPlanMember2020-01-012020-12-310001021635oge:OgAndEMemberus-gaap:StockCompensationPlanMember2019-01-012019-12-310001021635oge:OgAndEMemberus-gaap:StockCompensationPlanMember2018-01-012018-12-3100010216352020-03-312020-03-3100010216352020-09-302020-09-300001021635oge:TotalShareholderReturnMember2020-01-012020-12-310001021635oge:TotalShareholderReturnMember2019-01-012019-12-310001021635oge:TotalShareholderReturnMember2018-01-012018-12-310001021635oge:TotalShareholderReturnMemberoge:OgAndEMember2020-01-012020-12-310001021635oge:TotalShareholderReturnMemberoge:OgAndEMember2019-01-012019-12-310001021635oge:TotalShareholderReturnMemberoge:OgAndEMember2018-01-012018-12-310001021635oge:PerformanceUnitsRelatedToEarningsPerShareMember2018-01-012018-12-310001021635oge:OgAndEMemberoge:PerformanceUnitsRelatedToEarningsPerShareMember2018-01-012018-12-310001021635oge:PerformanceUnitsRelatedToEarningsPerShareMember2019-01-012019-12-310001021635oge:TotalShareholderReturnMember2019-12-310001021635oge:PerformanceUnitsRelatedToEarningsPerShareMember2019-12-310001021635us-gaap:RestrictedStockMember2019-12-310001021635oge:PerformanceUnitsRelatedToEarningsPerShareMember2020-01-012020-12-310001021635oge:TotalShareholderReturnMember2020-12-310001021635oge:PerformanceUnitsRelatedToEarningsPerShareMember2020-12-310001021635us-gaap:RestrictedStockMember2020-12-310001021635oge:TotalShareholderReturnMemberoge:OgAndEMember2019-12-310001021635oge:OgAndEMemberoge:PerformanceUnitsRelatedToEarningsPerShareMember2019-12-310001021635us-gaap:RestrictedStockMemberoge:OgAndEMember2019-12-310001021635oge:OgAndEMemberoge:PerformanceUnitsRelatedToEarningsPerShareMember2020-01-012020-12-310001021635oge:TotalShareholderReturnMemberoge:OgAndEMember2020-12-310001021635oge:OgAndEMemberoge:PerformanceUnitsRelatedToEarningsPerShareMember2020-12-310001021635us-gaap:RestrictedStockMemberoge:OgAndEMember2020-12-310001021635oge:OgAndEMemberoge:PerformanceUnitsRelatedToEarningsPerShareMember2019-01-012019-12-310001021635oge:DeferredTaxAssetMember2020-12-310001021635oge:ResearchAndDevelopmentCreditsMember2020-12-310001021635oge:StateOperatingLossMember2020-12-310001021635oge:OgAndEMemberoge:StateOperatingLossMember2020-12-310001021635oge:FederalTaxCreditsMemberMember2020-12-310001021635oge:FederalTaxCreditsMemberMemberoge:OgAndEMember2020-12-310001021635oge:OklahomaInvestmentTaxCreditsMemberMember2020-12-310001021635oge:OklahomaInvestmentTaxCreditsMemberMemberoge:OgAndEMember2020-12-310001021635oge:OklahomaCapitalInvestmentBoardCreditsMemberMember2020-12-310001021635oge:OgAndEMemberoge:OklahomaCapitalInvestmentBoardCreditsMemberMember2020-12-310001021635oge:OklahomaZeroEmissionTaxCreditsMemberMember2020-12-310001021635oge:OklahomaZeroEmissionTaxCreditsMemberMemberoge:OgAndEMember2020-12-310001021635oge:LouisianaInventoryCreditsMember2020-12-310001021635oge:LouisianaInventoryCreditsMemberoge:OgAndEMember2020-12-310001021635oge:AutomaticDividendReinvestmentAndStockPurchasePlanMember2020-01-012020-12-310001021635oge:AutomaticDividendReinvestmentAndStockPurchasePlanMember2020-12-310001021635us-gaap:DebenturesSubjectToMandatoryRedemptionMember2020-12-310001021635oge:NotExtendedMemberoge:OgeEnergyMember2020-12-310001021635oge:NotExtendedMemberoge:OgeEnergyMember2020-01-012020-12-3100010216352021-01-012021-03-310001021635us-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:PensionPlansDefinedBenefitMember2018-12-310001021635us-gaap:OtherPensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:OtherPensionPlansDefinedBenefitMember2018-12-310001021635oge:OgAndEMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:OgAndEMemberus-gaap:PensionPlansDefinedBenefitMember2018-12-310001021635us-gaap:OtherPensionPlansDefinedBenefitMemberoge:OgAndEMember2019-12-310001021635us-gaap:OtherPensionPlansDefinedBenefitMemberoge:OgAndEMember2018-12-310001021635us-gaap:OtherPensionPlansDefinedBenefitMember2020-01-012020-12-310001021635us-gaap:OtherPensionPlansDefinedBenefitMember2019-01-012019-12-310001021635oge:OgAndEMemberus-gaap:PensionPlansDefinedBenefitMember2020-01-012020-12-310001021635oge:OgAndEMemberus-gaap:PensionPlansDefinedBenefitMember2019-01-012019-12-310001021635us-gaap:OtherPensionPlansDefinedBenefitMemberoge:OgAndEMember2020-01-012020-12-310001021635us-gaap:OtherPensionPlansDefinedBenefitMemberoge:OgAndEMember2019-01-012019-12-310001021635us-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:OtherPensionPlansDefinedBenefitMember2020-12-310001021635oge:OgAndEMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:OtherPensionPlansDefinedBenefitMemberoge:OgAndEMember2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2018-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:OgAndEMember2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:OgAndEMember2018-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:OgAndEMember2020-01-012020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:OgAndEMember2019-01-012019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:OgAndEMember2020-12-310001021635us-gaap:PensionPlansDefinedBenefitMember2018-01-012018-12-310001021635us-gaap:OtherPensionPlansDefinedBenefitMember2018-01-012018-12-310001021635oge:OgAndEMemberus-gaap:PensionPlansDefinedBenefitMember2018-01-012018-12-310001021635us-gaap:OtherPensionPlansDefinedBenefitMemberoge:OgAndEMember2018-01-012018-12-310001021635stpr:OKus-gaap:PensionPlansDefinedBenefitMember2020-01-012020-12-310001021635stpr:OKus-gaap:PensionPlansDefinedBenefitMember2019-01-012019-12-310001021635stpr:OKus-gaap:PensionPlansDefinedBenefitMember2018-01-012018-12-310001021635stpr:ARus-gaap:PensionPlansDefinedBenefitMember2020-01-012020-12-310001021635stpr:ARus-gaap:PensionPlansDefinedBenefitMember2019-01-012019-12-310001021635stpr:ARus-gaap:PensionPlansDefinedBenefitMember2018-01-012018-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:OgAndEMember2018-01-012018-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberstpr:OK2020-01-012020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberstpr:OK2019-01-012019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberstpr:OK2018-01-012018-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberstpr:AR2020-01-012020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberstpr:AR2019-01-012019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberstpr:AR2018-01-012018-12-310001021635oge:LessThan90Member2020-01-012020-12-310001021635oge:A95Member2020-01-012020-12-310001021635oge:A100Member2020-01-012020-12-310001021635oge:A105Member2020-01-012020-12-310001021635oge:A110Member2020-01-012020-12-310001021635oge:A115Member2020-01-012020-12-310001021635oge:A120Member2020-01-012020-12-310001021635oge:DomesticAllCaplargeCapEquityMember2020-12-310001021635oge:DomesticAllCaplargeCapEquityMembersrt:MinimumMember2020-12-310001021635oge:DomesticAllCaplargeCapEquityMembersrt:MaximumMember2020-12-310001021635oge:DomesticMidCapEquityMember2020-12-310001021635oge:DomesticMidCapEquityMembersrt:MinimumMember2020-12-310001021635oge:DomesticMidCapEquityMembersrt:MaximumMember2020-12-310001021635oge:DomesticSmallCapEquityMember2020-12-310001021635oge:DomesticSmallCapEquityMembersrt:MinimumMember2020-12-310001021635srt:MaximumMemberoge:DomesticSmallCapEquityMember2020-12-310001021635oge:InternationalEquityMember2020-12-310001021635oge:InternationalEquityMembersrt:MinimumMember2020-12-310001021635srt:MaximumMemberoge:InternationalEquityMember2020-12-310001021635us-gaap:FairValueInputsLevel3Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:FairValueInputsLevel3Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:USCommonStocksMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:FairValueInputsLevel1Memberoge:USCommonStocksMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:USCommonStocksMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:USTreasurySecuritiesMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:USTreasurySecuritiesMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:USTreasurySecuritiesMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:MortgageBackedSecuritiesIssuedByUSGovernmentSponsoredEnterprisesMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:MortgageBackedSecuritiesIssuedByUSGovernmentSponsoredEnterprisesMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:MortgageBackedSecuritiesIssuedByUSGovernmentSponsoredEnterprisesMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:PensionPlansDefinedBenefitMemberus-gaap:CorporateDebtSecuritiesMember2020-12-310001021635us-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMemberus-gaap:CorporateDebtSecuritiesMember2020-12-310001021635us-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMemberus-gaap:CorporateDebtSecuritiesMember2020-12-310001021635us-gaap:PensionPlansDefinedBenefitMemberus-gaap:EquityFundsMember2020-12-310001021635us-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMemberus-gaap:EquityFundsMember2020-12-310001021635us-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMemberus-gaap:EquityFundsMember2020-12-310001021635us-gaap:ForeignGovernmentDebtSecuritiesMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:ForeignGovernmentDebtSecuritiesMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:ForeignGovernmentDebtSecuritiesMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:MunicipalBondsMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:FairValueInputsLevel1Memberus-gaap:MunicipalBondsMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:FairValueInputsLevel2Memberus-gaap:MunicipalBondsMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:MoneyMarketFundsMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:MoneyMarketFundsMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:MoneyMarketFundsMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:MutualFundMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:MutualFundMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:MutualFundMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:PreferredStockMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:PreferredStockMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:PreferredStockMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:CashCollateralMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:CashCollateralMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:CashCollateralMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:ReceivableForeignCurrencyMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:ReceivableForeignCurrencyMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:ReceivableForeignCurrencyMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:TotalPlanInvestmentsMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:FairValueInputsLevel1Memberoge:TotalPlanInvestmentsMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:FairValueInputsLevel2Memberoge:TotalPlanInvestmentsMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:ReceivableFromBrokerForSecuritiesSoldMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:InterestAndDividendsReceivableMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635us-gaap:PensionPlansDefinedBenefitMemberoge:PayableToBrokerForSecuritiesPurchasedMember2020-12-310001021635oge:TotalPlanAssetsMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:PlanInvestmentsAttributableToAffiliatesMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:TotalPlanAssetsMemberoge:OgAndEMemberus-gaap:PensionPlansDefinedBenefitMember2020-12-310001021635oge:USCommonStocksMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:FairValueInputsLevel1Memberoge:USCommonStocksMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:USCommonStocksMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:USTreasurySecuritiesMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:USTreasurySecuritiesMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:USTreasurySecuritiesMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:MortgageBackedSecuritiesIssuedByUSGovernmentSponsoredEnterprisesMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:MortgageBackedSecuritiesIssuedByUSGovernmentSponsoredEnterprisesMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:MortgageBackedSecuritiesIssuedByUSGovernmentSponsoredEnterprisesMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:PensionPlansDefinedBenefitMemberus-gaap:CorporateDebtSecuritiesMember2019-12-310001021635us-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMemberus-gaap:CorporateDebtSecuritiesMember2019-12-310001021635us-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMemberus-gaap:CorporateDebtSecuritiesMember2019-12-310001021635us-gaap:PensionPlansDefinedBenefitMemberus-gaap:EquityFundsMember2019-12-310001021635us-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMemberus-gaap:EquityFundsMember2019-12-310001021635us-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMemberus-gaap:EquityFundsMember2019-12-310001021635us-gaap:ForeignGovernmentDebtSecuritiesMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:ForeignGovernmentDebtSecuritiesMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:ForeignGovernmentDebtSecuritiesMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:MunicipalBondsMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:FairValueInputsLevel1Memberus-gaap:MunicipalBondsMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:FairValueInputsLevel2Memberus-gaap:MunicipalBondsMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:MoneyMarketFundsMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:MoneyMarketFundsMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:MoneyMarketFundsMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:MutualFundMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:MutualFundMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:MutualFundMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:PreferredStockMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:PreferredStockMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:PreferredStockMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:TreasuryfuturesreceivableMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:FairValueInputsLevel1Memberoge:TreasuryfuturesreceivableMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:FairValueInputsLevel2Memberoge:TreasuryfuturesreceivableMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:TreasuryfuturespayableMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:FairValueInputsLevel1Memberoge:TreasuryfuturespayableMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:FairValueInputsLevel2Memberoge:TreasuryfuturespayableMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:CashCollateralMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:CashCollateralMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:CashCollateralMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:ReceivableForeignCurrencyMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:ReceivableForeignCurrencyMemberus-gaap:FairValueInputsLevel1Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:ReceivableForeignCurrencyMemberus-gaap:FairValueInputsLevel2Memberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:TotalPlanInvestmentsMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:FairValueInputsLevel1Memberoge:TotalPlanInvestmentsMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:FairValueInputsLevel2Memberoge:TotalPlanInvestmentsMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:InterestAndDividendsReceivableMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:PensionPlansDefinedBenefitMemberoge:PayableToBrokerForSecuritiesPurchasedMember2019-12-310001021635oge:TotalPlanAssetsMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:PlanInvestmentsAttributableToAffiliatesMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635oge:TotalPlanAssetsMemberoge:OgAndEMemberus-gaap:PensionPlansDefinedBenefitMember2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel2Member2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel2Member2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:GroupRetireeMedicalInsuranceContractMember2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:GroupRetireeMedicalInsuranceContractMemberus-gaap:FairValueInputsLevel1Member2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:GroupRetireeMedicalInsuranceContractMemberus-gaap:FairValueInputsLevel3Member2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:USEquityMutualFundsInvestmentMember2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:USEquityMutualFundsInvestmentMemberus-gaap:FairValueInputsLevel1Member2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:USEquityMutualFundsInvestmentMemberus-gaap:FairValueInputsLevel3Member2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:CashMember2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel1Memberus-gaap:CashMember2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Memberus-gaap:CashMember2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel12And3Member2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel1Member2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Member2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:OgeEnergyMemberus-gaap:FairValueInputsLevel12And3Member2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:OgAndEMemberus-gaap:FairValueInputsLevel12And3Member2020-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:GroupRetireeMedicalInsuranceContractMember2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:GroupRetireeMedicalInsuranceContractMemberus-gaap:FairValueInputsLevel1Member2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:GroupRetireeMedicalInsuranceContractMemberus-gaap:FairValueInputsLevel3Member2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:USEquityMutualFundsInvestmentMember2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:USEquityMutualFundsInvestmentMemberus-gaap:FairValueInputsLevel1Member2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:USEquityMutualFundsInvestmentMemberus-gaap:FairValueInputsLevel3Member2019-12-310001021635us-gaap:CashMember2019-12-310001021635us-gaap:FairValueInputsLevel1Memberus-gaap:CashMember2019-12-310001021635us-gaap:FairValueInputsLevel3Memberus-gaap:CashMember2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel12And3Member2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel1Member2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:FairValueInputsLevel3Member2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:OgeEnergyMemberus-gaap:FairValueInputsLevel12And3Member2019-12-310001021635us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberoge:OgAndEMemberus-gaap:FairValueInputsLevel12And3Member2019-12-310001021635oge:ElectricUtilityMember2020-01-012020-12-310001021635oge:NaturalGasMidstreamOperationsMember2020-01-012020-12-310001021635us-gaap:AllOtherSegmentsMember2020-01-012020-12-310001021635us-gaap:IntersegmentEliminationMember2020-01-012020-12-310001021635oge:ElectricUtilityMember2020-12-310001021635oge:NaturalGasMidstreamOperationsMember2020-12-310001021635us-gaap:AllOtherSegmentsMember2020-12-310001021635us-gaap:IntersegmentEliminationMember2020-12-310001021635oge:ElectricUtilityMember2019-01-012019-12-310001021635oge:NaturalGasMidstreamOperationsMember2019-01-012019-12-310001021635us-gaap:AllOtherSegmentsMember2019-01-012019-12-310001021635us-gaap:IntersegmentEliminationMember2019-01-012019-12-310001021635oge:ElectricUtilityMember2019-12-310001021635oge:NaturalGasMidstreamOperationsMember2019-12-310001021635us-gaap:AllOtherSegmentsMember2019-12-310001021635us-gaap:IntersegmentEliminationMember2019-12-310001021635oge:ElectricUtilityMember2018-01-012018-12-310001021635oge:NaturalGasMidstreamOperationsMember2018-01-012018-12-310001021635us-gaap:AllOtherSegmentsMember2018-01-012018-12-310001021635us-gaap:IntersegmentEliminationMember2018-01-012018-12-310001021635oge:ElectricUtilityMember2018-12-310001021635oge:NaturalGasMidstreamOperationsMember2018-12-310001021635us-gaap:AllOtherSegmentsMember2018-12-310001021635us-gaap:IntersegmentEliminationMember2018-12-310001021635oge:OgeTotalCogenerationPaymentsMember2019-01-012019-12-310001021635oge:OgeTotalCogenerationPaymentsMember2018-01-012018-12-310001021635oge:OgeCapacityPaymentsMember2019-01-012019-12-310001021635oge:OgeCapacityPaymentsMember2018-01-012018-12-310001021635oge:OgeMinimumFuelPurchaseCommitmentsMember2020-12-310001021635oge:OgeExpectedWindPurchaseCommitmentsMember2020-12-310001021635oge:OgeLongTermServiceAgreementCommitmentsMember2020-12-310001021635oge:CpvKeenanMember2020-01-012020-12-310001021635oge:CpvKeenanMember2019-01-012019-12-310001021635oge:CpvKeenanMember2018-01-012018-12-310001021635oge:EdisonMissionEnergyMember2020-01-012020-12-310001021635oge:EdisonMissionEnergyMember2019-01-012019-12-310001021635oge:EdisonMissionEnergyMember2018-01-012018-12-310001021635oge:NexteraEnergyMember2020-01-012020-12-310001021635oge:NexteraEnergyMember2019-01-012019-12-310001021635oge:NexteraEnergyMember2018-01-012018-12-310001021635oge:FplEnergyMember2020-01-012020-12-310001021635oge:FplEnergyMember2019-01-012019-12-310001021635oge:FplEnergyMember2018-01-012018-12-310001021635oge:OgeLongTermServiceAgreementCommitmentsMemberoge:McclainPlantMember2020-01-012020-12-310001021635oge:RedbudPlantMemberoge:OgeLongTermServiceAgreementCommitmentsMember2020-01-012020-12-310001021635oge:OklahomaCorporationCommissionMember2020-01-012020-12-310001021635oge:ArkansasPublicServiceCommissionMember2020-01-012020-12-310001021635oge:FederalEnergyRegulatoryCommissionMember2020-01-012020-12-310001021635stpr:AR2019-01-012019-12-310001021635oge:ArkansasEnvironmentalMember2020-01-012020-12-310001021635oge:GridEnhancementMember2020-01-012020-12-310001021635oge:ImpacttoCompanyMember2020-12-310001021635oge:CustomerImpactMember2020-12-310001021635stpr:AR2020-01-012020-12-310001021635oge:InFavorCooperativesMember2020-12-310001021635srt:MinimumMember2020-01-012020-12-310001021635srt:MaximumMember2020-01-012020-12-310001021635oge:InFavorCooperativesMembersrt:MinimumMember2020-01-012020-12-310001021635oge:InFavorCooperativesMembersrt:MaximumMember2020-01-012020-12-310001021635srt:MinimumMember2020-12-310001021635srt:MaximumMember2020-12-31


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-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 Exact name of registrants as specified in their charters, address of principal executive offices and registrants' telephone number I.R.S. Employer Identification No.
1-12579 OGE ENERGY CORP. 73-1481638
1-1097 OKLAHOMA GAS AND ELECTRIC COMPANY 73-0382390
321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
405-553-3000

State or other jurisdiction of incorporation or organization: Oklahoma
Securities registered pursuant to Section 12(b) of the Act:
Registrant Title of each class Trading Symbol(s) Name of each exchange on which registered
OGE Energy Corp. Common Stock OGE New York Stock Exchange
Oklahoma Gas and Electric Company None N/A N/A

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.
OGE Energy Corp. þ  Yes  o  No        Oklahoma Gas and Electric Company þ  Yes  o  No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
OGE Energy Corp. o  Yes   þ  No        Oklahoma Gas and Electric Company o  Yes  þ  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.  
OGE Energy Corp. þ  Yes   o  No        Oklahoma Gas and Electric Company þ  Yes  o  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). 
OGE Energy Corp. þ  Yes   o  No        Oklahoma Gas and Electric Company þ  Yes  o  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 the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
OGE Energy Corp. Large Accelerated Filer þ Accelerated Filer o Non-accelerated Filer o Smaller reporting company
☐
Emerging growth company o
Oklahoma Gas and Electric Company Large Accelerated Filer o Accelerated Filer o Non-accelerated Filer þ Smaller reporting company
☐
Emerging growth company o
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.     OGE Energy Corp. ☑                Oklahoma Gas and Electric Company ☑
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
OGE Energy Corp. ☐  Yes   þ  No        Oklahoma Gas and Electric Company ☐ Yes   þ  No
At June 30, 2020, the last business day of OGE Energy Corp.'s most recently completed second fiscal quarter, the aggregate market value of shares of common stock held by non-affiliates was $6,077,156,282 based on the number of shares held by non-affiliates (200,169,838) and the reported closing market price of the common stock on the New York Stock Exchange on such date of $30.36.
At June 30, 2020, there was no voting or non-voting common equity of Oklahoma Gas and Electric Company held by non-affiliates.
At January 29, 2021, there were 200,021,161 shares of OGE Energy Corp.'s common stock, par value $0.01 per share, outstanding.
At January 29, 2021, there were 40,378,745 shares of Oklahoma Gas and Electric Company's common stock, par value $2.50 per share, outstanding, all of which were held by OGE Energy Corp. There were no other shares of capital stock of the registrant outstanding at such date.

DOCUMENTS INCORPORATED BY REFERENCE
The Proxy Statement for OGE Energy Corp.'s 2021 annual meeting of shareowners is incorporated by reference into Part III of this Form 10-K.
This combined Form 10-K represents separate filings by OGE Energy Corp. and Oklahoma Gas and Electric Company. Information contained herein related to an individual registrant is filed by such registrant on its own behalf. Oklahoma Gas and Electric Company makes no representations as to the information relating to OGE Energy Corp.'s other operations.
Oklahoma Gas and Electric Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).



FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2020

TABLE OF CONTENTS

Page
ii
1
2
5
15
45
Item 2. Properties
46
47
47
48
48
72
73
141
141
145
145
145
145
145
146
147
153
154

i

GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations that are found throughout this Form 10-K.
Abbreviation Definition
2019 Form 10-K Annual Report on Form 10-K for the year ended December 31, 2019
401(k) Plan Qualified defined contribution retirement plan
APSC Arkansas Public Service Commission
ArcLight group Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC, collectively
ASC FASB Accounting Standards Codification
ASU FASB Accounting Standards Update
CenterPoint CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
CO2
Carbon dioxide
Code Internal Revenue Code of 1986
COVID-19 Novel Coronavirus disease
Dry Scrubber Dry flue gas desulfurization unit with spray dryer absorber
EGT Enable Gas Transmission, LLC, a wholly-owned subsidiary of Enable that operates an approximately 5,900-mile interstate pipeline that provides natural gas transportation and storage services to customers principally in the Anadarko, Arkoma and Ark-La-Tex Basins in Oklahoma, Texas, Arkansas, Louisiana, Missouri and Kansas
Enable Enable Midstream Partners, LP, partnership between OGE Energy, the ArcLight group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint
Energy Transfer Energy Transfer LP, a Delaware limited partnership
Enogex Holdings Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings, LLC (prior to May 1, 2013)
Enogex LLC Enogex LLC, collectively with its subsidiaries (effective June 30, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC)
EOIT Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly-owned subsidiary of Enable that operates an approximately 2,200-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma
EPA U.S. Environmental Protection Agency
FASB Financial Accounting Standards Board
Federal Clean Air Act Federal Clean Air Act of 1970, as amended
Federal Clean Water Act Federal Water Pollution Control Act of 1972, as amended
FERC Federal Energy Regulatory Commission
FIP Federal Implementation Plan
GAAP Accounting principles generally accepted in the U.S.
kV Kilovolt
LDC Local distribution company involved in the delivery of natural gas to consumers within a specific geographic area
MATS Mercury and Air Toxics Standards
MBbl/d Thousand barrels per day
MMBtu Million British thermal unit
MRT Enable Mississippi River Transmission, LLC, a wholly-owned subsidiary of Enable that operates an approximately 1,600-mile interstate pipeline that provides natural gas transportation and storage services principally in Texas, Arkansas, Louisiana, Missouri and Illinois
MW Megawatt
MWh Megawatt-hour
NAAQS National Ambient Air Quality Standards
NERC North American Electric Reliability Corporation
NGLs
Natural gas liquids, which are the hydrocarbon liquids contained within the natural gas stream including condensate
NOX
Nitrogen oxide
OCC Oklahoma Corporation Commission
ODEQ Oklahoma Department of Environmental Quality
OG&E Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
OGE Energy OGE Energy Corp., collectively with its subsidiaries, holding company and parent company of OG&E
OGE Holdings OGE Enogex Holdings LLC, wholly-owned subsidiary of OGE Energy, parent company of Enogex Holdings (prior to May 1, 2013) and 25.5 percent owner of Enable
OSHA Federal Occupational Safety and Health Act of 1970
Pension Plan Qualified defined benefit retirement plan
ii

QF contract Contract with qualified cogeneration facilities and small power production producers
Regional Haze Rule The EPA's Regional Haze Rule
Registrants OGE Energy and OG&E
Restoration of Retirement Income Plan Supplemental retirement plan to the Pension Plan
SESH Southeast Supply Header, LLC, in which Enable owns a 50 percent interest as of December 31, 2020, that operates an approximately 290-mile interstate natural gas pipeline from Perryville, Louisiana to southwestern Alabama near the Gulf Coast
SIP State Implementation Plan
SO2
Sulfur dioxide
SPP Southwest Power Pool
Stock Incentive Plan 2013 Stock Incentive Plan
System sales Sales to OG&E's customers
TBtu/d Trillion British thermal units per day
U.S. United States of America
Wells Fargo
Wells Fargo Bank, National Association

iii

FILING FORMAT

This combined Form 10-K is separately filed by OGE Energy and OG&E. Information in this combined Form 10-K relating to each individual Registrant is filed by such Registrant on its own behalf. OG&E makes no representation regarding information relating to any other companies affiliated with OGE Energy. Neither OGE Energy, nor any of OGE Energy's subsidiaries, other than OG&E, has any obligation in respect of OG&E's debt securities, and holders of such debt securities should not consider the financial resources or results of operations of OGE Energy nor any of OGE Energy's subsidiaries, other than OG&E (in relevant circumstances), in making a decision with respect to OG&E's debt securities. Similarly, none of OG&E nor any other subsidiary of OGE Energy has any obligation with respect to debt securities of OGE Energy. This combined Form 10-K should be read in its entirety. No one section of this combined Form 10-K deals with all aspects of the subject matter of this combined Form 10-K.

FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed within this Form 10-K, including those matters discussed within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "believe," "estimate," "expect," "intend," "objective," "plan," "possible," "potential," "project," "target" and similar expressions. Actual results may vary materially from those expressed in forward-looking statements. In addition to the specific risk factors discussed within "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

•general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;
•the ability of OGE Energy and its subsidiaries to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;
•the ability to obtain timely and sufficient rate relief to allow for recovery of items such as capital expenditures, fuel costs, operating costs, transmission costs and deferred expenditures;
•prices and availability of electricity, coal, natural gas and NGLs;
•for OGE Energy, the timing and extent of changes in commodity prices, particularly natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions Enable serves and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable's interstate pipelines;
•for OGE Energy, the timing and extent of changes in the supply of natural gas, particularly supplies available for gathering by Enable's gathering and processing business and transporting by Enable's interstate and intrastate pipelines, including the impact of natural gas and NGLs prices on the level of drilling and production activities in the regions Enable serves;
•for OGE Energy, business conditions in the energy and natural gas midstream industries, including the demand for natural gas, NGLs, crude oil and midstream services;
•competitive factors, including the extent and timing of the entry of additional competition in the markets served by the Registrants;
•the impact on demand for services resulting from cost-competitive advances in technology, such as distributed electricity generation and customer energy efficiency programs;
•technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets;
•factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, natural gas or coal supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;
•availability and prices of raw materials for current and future construction projects;
•the effect of retroactive pricing of transactions in the SPP markets or adjustments in market pricing mechanisms by the SPP;
•federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Registrants' markets;
•environmental laws, safety laws or other regulations that may impact the cost of operations or restrict or change the way the Registrants' facilities are operated;
•changes in accounting standards, rules or guidelines;
•the discontinuance of accounting principles for certain types of rate-regulated activities;


1

•the cost of protecting assets against, or damage due to, terrorism or cyberattacks and other catastrophic events;
•creditworthiness of suppliers, customers and other contractual parties;
•social attitudes regarding the utility, natural gas and power industries;
•identification of suitable investment opportunities to enhance shareholder returns and achieve long-term financial objectives through business acquisitions and divestitures;
•increased pension and healthcare costs;
•the impact of extraordinary external events, such as the current pandemic health event resulting from COVID-19, and their collateral consequences, including extended disruption of economic activity in the Registrants' markets;
•costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including, but not limited to, those described in this Form 10-K;
•difficulty in making accurate assumptions and projections regarding future revenues and costs associated with OGE Energy's equity investment in Enable that OGE Energy does not control;
•Enable's pending merger with Energy Transfer and the expected timing of the consummation of the merger; and
•other risk factors listed in the reports filed by the Registrants with the Securities and Exchange Commission, including those listed within "Item 1A. Risk Factors" herein.

The Registrants undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

SUMMARY OF RISK FACTORS

The Registrants are subject to a variety of risks and uncertainties, including regulatory risks, operational risks, financial risks and certain general risks. Risks of OG&E are also risks of OGE Energy. OGE Energy also is subject to risks associated with its investment in Enable. These risks could have a material adverse effect on the Registrants' business, financial condition, results of operations and cash flows. Risks that the Registrants deem material are described under "Risk Factors" within "Item 1A. Risk Factors" herein. These risks include, but are not limited to, the following.
Pg.
Regulatory Risks
• Profitability depends on the ability to recover costs from OG&E's customers in a timely manner.
15
• OG&E's rates are subject to various regulatory agencies whose regulatory paradigms and goals may differ.
15
• Costs of compliance with environmental laws and regulations are significant and may increase with the new Biden administration.
16
• Costs of the Registrants' investments in capital improvements and additions may not be recoverable.
16
• The regional power market in which OG&E operates has changing transmission regulatory structures.
16
• The Registrants may face increased competition resulting from changes to the utility and energy markets.
17
• The Registrants are subject to compliance with substantial utility and energy regulation.
17
Operational Risks
• Results of operations may be impacted by disruptions to the Registrants' fuel supply or the electric grid that are beyond the Registrants' control.
17
• OG&E's electric assets are subject to various operational risks, including outages and accidents.
17
• Changes in technology, regulatory policies and customer electricity consumption may cause the Registrants' assets to be less competitive.
18
• The Registrants may be impacted by severe weather conditions, as well as seasonal temperature variations.
18
Financial Risks
• The Registrants may be impacted by changes related to their Pension Plan and health care plans, including market performance, increased retirements, change in regulations and increasing costs.
18
• OGE Energy is a holding company with its primary assets being investments in other companies.
19
Risks Associated with OGE Energy's Investment in Enable
• OGE Energy does not control Enable and therefore cannot cause or prevent certain actions by Enable.
19
• OGE Energy's operating cash flow is derived partially from cash distributions received from Enable.
20
• Enable's contracts are subject to renewal risks.
20
• Enable's businesses are dependent, in part, on the drilling and production decisions of others, which are impacted by demand and commodity prices.
21
• Enable's industry is highly competitive.
22


2

• Natural gas, NGLs and crude prices are volatile.
22
• A pandemic, epidemic or outbreak of an infectious disease may materially adversely affect Enable's business.
22
• Enable has contracts that provide services under fixed prices, which could result in costs exceeding revenues.
23
• If third-party facilities that interconnect with Enable's facilities are unavailable, Enable may be impacted.
23
• Enable does not own all of the land on which its facilities are located, which could disrupt its operations.
24
• An impairment of long-lived assets could reduce Enable's earnings.
24
• Enable's business involves hazards and operational risks, some of which may not be fully covered by insurance.
24
• The use of derivative contracts could result in financial losses.
25
• Failure to attract and retain an appropriately qualified workforce could adversely impact Enable.
25
• Cybersecurity attacks or other disruptions to Enable's systems and networks could have adverse impacts.
25
• Terrorist attacks or other physical threats could adversely affect Enable's business.
26
• If Enable fails to maintain effective internal controls, reported financial results could be affected.
26
• Enable is dependent on a small number of customers for a significant portion of its revenues.
26
• Enable is exposed to the credit risk of its customers.
26
• Enable's debt levels may limit its flexibility in obtaining additional financing or pursuing business opportunities.
26
• Enable's credit facilities contain restrictions that may be affected by events beyond its control.
27
• Any reductions in Enable's credit ratings could increase financing costs.
27
• Enable may not be able to recover the costs of substantial planned investment in capital improvements.
28
• Enable's ability to grow is dependent in part on its access to external financing sources on acceptable terms.
28
• Enable's merger and acquisition activities may not be successful.
29
• Enable may be unable to obtain or renew permits necessary for its operations.
29
• Enable's operations may be impacted by certain indigenous rights protections.
29
• Costs of compliance with environmental laws and regulations are significant.
30
• Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by Enable's customers.
30
• Enable and its customers' operations are subject to risks related to the threat of climate change.
31
• Enable's operations are subject to extensive federal regulations.
32
• Enable's operations are subject to state and local regulations.
34
• A change in jurisdictional characterization of Enable's assets by regulators could result in increased regulation.
34
• Enable may incur significant costs related to compliance with pipeline safety laws and regulations.
34
• The Dodd-Frank Act regulations could affect Enable's ability to hedge risks associated with its business.
35
• Enable derives a substantial portion of its gross margin from subsidiaries.
36
• Enable conducts a portion of its operations through joint ventures, which subjects them to additional risks.
36
• Under certain circumstances, Enbridge Inc. could have the right to purchase an ownership interest in SESH.
36
• The amount of cash Enable has available for distribution depends on cash flow rather than profitability.
37
• Affiliates of Enable's general partner may compete with Enable.
37
• Enable may issue additional units without unitholder approval, which could dilute existing ownership.
38
• Affiliates of Enable's general partner may sell common units, which could impact the trading price of units.
38
• Enable's Series A Preferred Units have rights and privileges that are preferential to those of common units.
38
• Enable's Series A Preferred Units contain covenants that may limit business flexibility.
39
• Enable's Series A Preferred units are required to be redeemed in certain circumstances.
39
• Enable's unitholders cannot be certain of the precise value of any Energy Transfer merger consideration they may receive.
39
• The Energy Transfer merger may not be completed and the merger agreement may be terminated.
39
• The Energy Transfer merger agreement limits Enable's ability to pursue alternatives to the merger.
40
• Failure to complete the Energy Transfer merger could negatively impact Enable's future financial results.
40
• Enable will be subject to business uncertainties while the merger is pending.
40


3

• The common units representing limited partner interests in Energy Transfer will have different rights than Enable's common units.
41
• Completion of the Energy Transfer merger may trigger change in control or other provisions in certain Enable agreements.
41
• Enable will incur significant transaction and merger-related costs in connection with the Energy Transfer merger.
41
• Enable may be a target of securities class action and derivative lawsuits as a result of the Energy Transfer merger.
41
General Risks
• Events that are beyond the Registrants' control have increased public and regulatory scrutiny of their industry.
41
• Economic conditions could negatively impact the Registrants' business.
42
• The Registrants are subject to financial risks associated with climate change.
42
• The Registrants are subject to cybersecurity risks and increased reliance on processes automated by technology.
42
• Terrorist attacks, and the threat of terrorist attacks, have increased costs to the Registrants' business.
43
• The Registrants face risks related to health epidemics and other outbreaks.
43
• The Registrants face risks related to the availability of trained and qualified labor to meet their staffing requirements.
44
• Certain provisions in the Registrants' charter documents have anti-takeover effects.
44
• The Registrants may be able to incur substantially more indebtedness, which can increase the associated risks.
44
• Changes to the Registrants' credit ratings or benchmark interest rates could impact their financing costs.
44
• The Registrants' debt levels may limit their flexibility in obtaining additional financing or pursuing business opportunities.
45
• The Registrants are exposed to the credit risk of their key customers and counterparties.
45



4


PART I

Item 1. Business.
 
Introduction
 
OGE Energy, incorporated in August 1995 in the State of Oklahoma, is a holding company with investments in energy and energy services providers offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S. OGE Energy conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations.  
  
OG&E. OGE Energy's electric utility operations are conducted through OG&E, which generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. OG&E's rates are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is a wholly-owned subsidiary of OGE Energy. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

Enable. OGE Energy's natural gas midstream operations segment represents OGE Energy's investment in Enable. The investment in Enable is held through wholly-owned subsidiaries and ultimately OGE Holdings. Enable is primarily engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns crude oil gathering assets in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama. At December 31, 2020, OGE Energy owned 111.0 million common units, or 25.5 percent, of Enable's outstanding common units.

On February 16, 2021, Enable entered into a definitive merger agreement with Energy Transfer, pursuant to which, and subject to the conditions of the merger agreement, all outstanding common units of Enable will be acquired by Energy Transfer in an all-equity transaction. Under the terms of the merger agreement, Enable's common unitholders, including OGE Energy, will receive 0.8595 of one common unit representing limited partner interests in Energy Transfer for each common unit of Enable. The transaction is anticipated to close in 2021. The transaction is subject to the receipt of the required approvals from the holders of a majority of Enable's common units, anti-trust approvals and other customary closing conditions. Assuming the transaction closes, OGE Energy will own approximately three percent of Energy Transfer's outstanding limited partner units in lieu of the 25.5 percent interest in Enable that it currently owns. Energy Transfer owns and operates one of the largest and most diversified portfolios of energy assets in the U.S., with a strategic footprint in all of the major domestic production basins. Energy Transfer is a publicly traded limited partnership with core operations that include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, NGL and refined product transportation and terminalling assets; NGL fractionation; and various acquisition and marketing assets.

See "Enable's Pending Merger with Energy Transfer" within "Item 1A. Risk Factors" for a discussion of risks related to the Enable and Energy Transfer merger.

The Registrants' principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma, 73101-0321 (telephone 405-553-3000). OGE Energy's website address is www.ogeenergy.com. Through OGE Energy's website under the heading "Investors," "SEC Filings," OGE Energy makes available, free of charge, the Registrants' annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. OGE Energy's website and the information contained therein or connected thereto are not intended to be incorporated into this Form 10-K and should not be considered a part of this Form 10-K. Reports filed with the Securities and Exchange Commission are also made available on its website at www.sec.gov.



5

Strategy
 
OGE Energy's purpose is to energize life, providing life-sustaining and life-enhancing products and services, while honoring its commitment to strengthen communities. Its business model is centered around growth and sustainability for employees (internally referred to as "members"), communities and customers and the owners of OGE Energy, its shareholders.

OGE Energy is focused on:

•continuing to deliver top-quartile safety results, while enabling members to deliver improved value to their communities, customers and shareholders;
•transforming the customer experience with the right balance of personalized interaction and technology that allows our customers to self-serve;
•providing safe, reliable energy to the communities and customers it serves, with a particular focus on enhancing the value of the grid by improving reliability and resiliency;
•leading economic development and job growth by attracting new and diverse businesses to improve the infrastructure of the communities in Oklahoma and Arkansas;
•ensuring the necessary mix of generation resources to meet the long-term capacity needs of our customers, with a progressively cleaner generation portfolio;
•continuing focus on innovation, intellectual curiosity and executing with excellence in order to maintain customer rates that are some of the most affordable in the country;
•delivering on earnings commitments to shareholders to enhance access to lower-cost debt and equity capital that is needed to deploy infrastructure for the long-term economic health of its communities;
•having strong regulatory and legislative relationships, built on integrity, for the long-term benefit of our customers, communities, shareholders and members; and
•developing and growing our members to be able to provide a greater contribution to the company's success, while also improving their own lives.

OGE Energy is focused on creating long-term shareholder value by targeting the consistent growth of earnings per share of five percent at the electric utility, underscored by a strategy of investing in lower risk infrastructure projects that improve the economic vitality of the communities it serves in Oklahoma and Arkansas. OGE Energy utilizes cash distributions from its natural gas midstream operations segment to help fund its electric utility capital investments. OGE Energy's financial objectives also include maintaining investment grade credit ratings and providing a strong and reliable dividend for shareholders.

OGE Energy's long-term sustainability is predicated on providing exceptional customer experiences, investing in grid improvements and increasingly cleaner generation resources, environmental stewardship, strong governance practices and caring for and supporting its members and communities.
Electric Operations - OG&E

General

OG&E furnishes retail electric service in 267 communities and their contiguous rural and suburban areas. The service area covers 30,000 square miles in Oklahoma and western Arkansas, including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas, the second largest city in that state. Of the 267 communities that OG&E serves, 241 are located in Oklahoma, and 26 are in Arkansas. OG&E derived 92 percent of its total electric operating revenues in 2020 from sales in Oklahoma and the remainder from sales in Arkansas. OG&E does not currently serve wholesale customers in either state.

OG&E's system control area peak demand in 2020 was 6,437 MWs on August 28, 2020. OG&E's load responsibility peak demand was 5,711 MWs on August 28, 2020. The following table presents system sales and variations in system sales for 2020, 2019 and 2018.
Year Ended December 31  2020 2020 vs. 2019 2019 2019 vs. 2018 2018
System sales (Millions of MWh)
27.0 (4.9)% 28.4 1.1% 28.1

OG&E is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity.


6

Besides competition from other suppliers or marketers of electricity, OG&E competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy. It is possible that changes in regulatory policies or advances in technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells will reduce costs of new technology to levels that are equal to or below that of most central station electricity production. OG&E's ability to maintain relatively low cost, efficient and reliable operations is a significant determinant of its competitiveness.

OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
Year Ended December 31 2020 2019 2018
ELECTRIC ENERGY (Millions of MWh)
Generation (exclusive of station use) 17.5  17.0  18.2 
Purchased 12.9  14.0  12.6 
Total generated and purchased 30.4  31.0  30.8 
OG&E use, free service and losses (1.4) (1.4) (1.3)
Electric energy sold 29.0  29.6  29.5 
ELECTRIC ENERGY SOLD (Millions of MWh)
Residential 9.5  9.7  9.7 
Commercial 6.3  6.5  6.6 
Industrial 4.2  4.5  4.5 
Oilfield 4.2  4.6  4.2 
Public authorities and street light 2.8  3.1  3.1 
System sales 27.0  28.4  28.1 
Integrated market 2.0  1.2  1.4 
Total sales 29.0  29.6  29.5 
ELECTRIC OPERATING REVENUES (In millions)
Residential $ 869.0  $ 891.1  $ 901.0 
Commercial 479.4  503.1  519.9 
Industrial 197.3  223.0  234.5 
Oilfield 172.3  204.0  193.5 
Public authorities and street light 176.8  195.7  204.0 
Sales for resale 0.1  0.1  0.2 
System sales revenues 1,894.9  2,017.0  2,053.1 
Provision for rate refund 3.8  (0.9) (6.0)
Integrated market 49.6  38.4  48.7 
Transmission 143.3  148.0  147.4 
Other 30.7  29.1  27.1 
Total operating revenues $ 2,122.3  $ 2,231.6  $ 2,270.3 
ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period)
Residential 740,174  731,797  725,440 
Commercial 100,200  98,565  96,660 
Industrial 2,710  2,965  3,072 
Oilfield 6,822  7,071  7,110 
Public authorities and street light 17,483  17,356  17,090 
Total customers 867,389  857,754  849,372 
AVERAGE RESIDENTIAL CUSTOMER SALES
Average annual revenue $ 1,180.82  $ 1,223.05  $ 1,247.22 
Average annual use (kilowatt-hour)
12,848  13,344  13,466 
Average price per kilowatt-hour (cents)
9.19  9.17  9.26 



7

Regulation and Rates

OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations. In 2020, 86 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and six percent to the FERC.

The OCC and the APSC require that, among other things, (i) OGE Energy permits the OCC and the APSC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E; (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers; and (iii) OGE Energy refrain from pledging OG&E assets or income for affiliate transactions. In addition, the FERC has access to the books and records of OGE Energy and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.

For information concerning OG&E's recently completed and currently pending regulatory proceedings, see Note 16 within "Item 8. Financial Statements and Supplementary Data."

Regulatory Assets and Liabilities
OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.

OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates. Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets or liabilities, which could have significant financial effects. See Note 1 within "Item 8. Financial Statements and Supplementary Data" for further discussion of OG&E's regulatory assets and liabilities.

Rate Structures
Oklahoma
OG&E's standard tariff rates include a cost of service component (including an authorized return on capital) plus a fuel adjustment clause mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power.
OG&E offers several alternative customer programs and rate options, as described below.
•Under OG&E's Smart Grid-enabled SmartHours programs, "time-of-use" and "variable peak pricing" rates offer customers the ability to save on their electricity bills by shifting some of the electricity consumption to off-peak times when demand for electricity is lowest.
•The guaranteed flat bill option for residential and small general service accounts allows qualifying customers the opportunity to purchase their electricity needs at a set monthly price for an entire year.
•The Renewable Energy Credit purchase program, a rate option that provides a "renewable energy" resource, is available as a voluntary option to all of OG&E's Oklahoma retail customers. OG&E's ownership and access to wind and solar resources makes the renewable option a possible choice in meeting the renewable energy needs of OG&E's conservation-minded customers.
•Load Reduction is a voluntary load curtailment program that provides OG&E's commercial and industrial customers with the opportunity to curtail usage on a voluntary basis when OG&E's system conditions merit curtailment action. Customers that curtail their usage will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days but may not be able to curtail every time that a curtailment event is required.


8

•OG&E offers certain qualifying customers "day-ahead price" and "flex price" rate options which allow participating customers to adjust their electricity consumption based on price signals received from OG&E. The prices for the "day-ahead price" and "flex price" rate options are based on OG&E's projected next day hourly operating costs.

OG&E has Public Schools-Demand and Public Schools Non-Demand rate classes that provide OG&E with flexibility to provide targeted programs for load management to public schools and their unique usage patterns. OG&E also provides service level, seasonal and time period fuel charge differentiation that allows customers to pay fuel costs that better reflect the underlying costs of providing electric service. Lastly, OG&E has a military base rider that demonstrates Oklahoma's continued commitment to our military partners.
The previously discussed rate options, coupled with OG&E's other rate choices, provide many tariff options for OG&E's Oklahoma retail customers. The revenue impacts associated with these options are not determinable in future years because customers may choose to remain on existing rate options instead of volunteering for the alternative rate option choices. Revenue variations may occur in the future based upon changes in customers' usage characteristics if they choose alternative rate options.
Arkansas

OG&E's standard tariff rates include a cost of service component (including an authorized return on capital) plus an energy cost recovery mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power. OG&E's current rate order from the APSC includes a formula rate rider that provides for an annual adjustment to rates if the earned rate of return falls outside of a plus or minus 50 basis point dead-band around the allowed return on equity. Adjustments are limited to plus or minus four percent of revenue for each rate class for the 12 months preceding the test period. The initial term for the formula rate rider is not to exceed five years from the date of the APSC final order in the last general rate review, May 18, 2017, unless additional approval is obtained from the APSC.

OG&E offers several alternative customer programs and rate options, as described below.

•The "time-of-use" and "variable peak pricing" tariffs allow participating customers to save on their electricity bills by shifting some of the electricity consumption to off-peak times when demand for electricity is lowest.
•The Renewable Energy Credit purchase program, a tariff rate option that provides a "renewable energy" resource, is available as a voluntary option to all of OG&E's Arkansas retail customers. OG&E's ownership and access to wind resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers.
•Load Reduction is a voluntary load curtailment program that provides OG&E's commercial and industrial customers with the opportunity to curtail usage on a voluntary basis and receive a billing credit when OG&E's system conditions merit curtailment action.
•OG&E offers certain qualifying customers a "day-ahead price" rate option which allows participating customers to adjust their electricity consumption based on a price signal received from OG&E. The "day-ahead price" is based on OG&E's projected next day hourly operating costs.

Fuel Supply and Generation
The following table presents the OG&E-generated energy produced and the weighted average cost of fuel used, by type, for the last three years.
Fuel Mix (A)
Fuel Cost
(In cents/Kilowatt-Hour)
2020 2019 2018 2020 2019 2018
Natural gas 66% 64% 48% 2.077 2.188 2.517
Coal 26% 28% 45% 1.821 2.029 2.025
Renewable 8% 8% 7% — — —
Total fuel 100% 100% 100% 1.863 1.970 2.119
(A)Fuel mix calculated as a percent of net MWhs generated.

The decreases in the weighted average cost of fuel in 2020 compared to 2019 and 2019 compared to 2018 were primarily due to lower fuel prices year over year. These fuel costs are recovered through OG&E's fuel adjustment clauses that are approved by the OCC and the APSC.


9


OG&E participates in the SPP Integrated Marketplace. As part of the Integrated Marketplace, the SPP has balancing authority responsibilities for its market participants. The SPP Integrated Marketplace functions as a centralized dispatch, where market participants, including OG&E, submit offers to sell power to the SPP from their resources and bid to purchase power from the SPP for their customers. The SPP Integrated Marketplace is intended to allow the SPP to optimize supply offers and demand bids based upon reliability and economic considerations and to determine which generating units will run at any given time for maximum cost-effectiveness within the SPP area. As a result, OG&E's generating units produce output that is different from OG&E's customer load requirements. Net fuel and purchased power costs are recovered through fuel adjustment clauses.

Of OG&E's 7,120 total MWs of generation capability reflected in the table within "Item 2. Properties," 4,795 MWs, or 67.4 percent, are from natural gas generation, 1,534 MWs, or 21.5 percent, are from coal generation, 320 MWs, or 4.5 percent, are from dual-fuel generation (coal/gas), 449 MWs, or 6.3 percent, are from wind generation and 22 MWs, or 0.3 percent, are from solar generation.
Natural Gas
As a participant in the SPP Integrated Marketplace, OG&E purchases its natural gas supply through short-term agreements. OG&E relies on a combination of natural gas base load agreements and call agreements, whereby OG&E has the right but not the obligation to purchase a defined quantity of natural gas, combined with day and intra-day purchases to meet the demands of the SPP Integrated Marketplace.
Coal
OG&E's coal-fired units are designed to burn primarily low sulfur western sub-bituminous coal. The combination of all 2020 coal purchased had a weighted average sulfur content of 0.2 percent. Based on the average sulfur content and EPA-certified data, OG&E's coal units have an approximate emission rate of 0.1 lbs. of SO2 per MMBtu.
For the first two quarters of 2021, OG&E has coal supply agreements for 100 percent of its coal requirements for the Sooner, Muskogee and River Valley facilities. OG&E plans to fill the remainder of its 2021 coal needs through additional term agreements, spot purchases and the use of existing inventory. OG&E has no coal agreements beyond June 2021. In 2020, OG&E purchased 2.518 million tons of coal from its Wyoming supplier and 0.027 million tons from its Oklahoma supplier. See "Environmental Laws and Regulations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of environmental matters which may affect OG&E in the future, including its utilization of coal.
Wind
OG&E owns the 120 MW Centennial, 101 MW OU Spirit and 228 MW Crossroads wind farms. OG&E's current wind power portfolio also includes purchased power contracts as presented in the following table.
Company Location Original Term of Contract Expiration of Contract MWs
CPV Keenan Woodward County, OK 20 years 2030 152.0
Edison Mission Energy Dewey County, OK 20 years 2031 130.0
NextEra Energy Blackwell, OK 20 years 2032 60.0

Solar

OG&E currently owns and operates, or will operate, the solar farms presented in the following table.
Name Location Year Completed Photovoltaic Panels MWs
Mustang Oklahoma City, OK 2015 9,867 2.5
Covington Covington, OK 2018 38,000 9.7
Choctaw Nation Durant, OK 2020 15,344 5.0
Chickasaw Nation Davis, OK 2020 15,344 5.0
Branch Branch, AR In progress 15,444 5.0



10

OG&E will continue to evaluate the need to add additional solar sites to its generation portfolio based on customer demand, cost and reliability.

Safety and Health Regulation
 
OG&E is subject to a number of federal and state laws and regulations, including OSHA, the EPA and comparable state statutes, whose purpose is to protect the safety and health of workers.

In addition, the OSHA Hazard Communication Standard, the EPA Emergency Planning and Community Right-to-Know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials stored, used or produced in OG&E's operations and that this information be provided or made available to employees, state and local government authorities and citizens. OG&E believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.

Natural Gas Midstream Operations - Enable

Overview
 
Enable is a publicly traded Delaware limited partnership that owns, operates and develops strategically located natural gas and crude oil infrastructure assets. Enable serves current and emerging production areas in the U.S., including several unconventional shale resource plays and local and regional end-user markets in the U.S. Enable's assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Enable's gathering and processing segment primarily provides natural gas gathering and processing to its producer customers and crude oil, condensate and produced water gathering services to its producer and refiner customers. Enable's transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to its producer, power plant, LDC and industrial end-user customers.

Gathering and Processing

Enable owns and operates substantial natural gas gathering and processing and crude oil, condensate and produced water gathering assets primarily in five states. Enable's gathering and processing operations consist primarily of natural gas gathering and processing assets serving the Anadarko, Arkoma and Ark-La-Tex Basins, crude oil and condensate gathering assets serving the Anadarko Basin and crude oil and produced water gathering assets serving the Williston Basin. Enable provides a variety of services to the active producers in its operating areas, including gathering, compressing, treating and processing natural gas, fractionating NGLs and gathering crude oil, condensate and produced water. Enable serves shale and other unconventional plays in the basins in which it operates.

Enable generates revenues from producers in the basins in which it operates. For the year ended December 31, 2020, Enable's top ten natural gas producer customers accounted for approximately 70 percent of its natural gas gathered volumes. Enable's Anadarko Basin crude oil gathering system gathers crude oil and condensate from producers, which are primarily delivered to one customer. The rates and terms of service on Enable's Anadarko Basin crude oil and condensate gathering systems are regulated by the OCC. Enable's Williston Basin crude oil and produced water gathering systems serve one customer. The rates and terms of service on Enable's Williston Basin crude oil gathering systems, but not its produced water gathering systems, are regulated by the FERC. Enable's contracts typically provide for crude oil, condensate and produced water gathering services that are fee-based, for natural gas gathering services that are fee-based and for natural gas processing arrangements that are fee-based, or percent-of-liquids, percent-of-proceeds or keep-whole based.

Competition for Enable's gathering and processing systems is primarily a function of gathering rate, processing value, system reliability, fuel rate, system run time, construction cycle time and prices at the wellhead. Enable's gathering and processing systems compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. In the process of selling NGLs, Enable competes against other natural gas processors extracting and selling NGLs. Enable's primary competitors are other midstream companies who are active in the regions where Enable operates.

While the results of Enable's gathering and processing segment are not materially affected by seasonality, from time to time, its operations and construction of assets can be impacted by inclement weather.




11

Transportation and Storage

Enable owns and operates interstate and intrastate natural gas transportation and storage systems primarily across nine states. Enable's transportation and storage systems consist primarily of its interstate systems, EGT and MRT, its intrastate system, EOIT, and its investment in SESH. Enable's transportation and storage assets transport natural gas from areas of production and interconnected pipelines to power plants, LDCs and industrial end users as well as interconnected pipelines for delivery to additional markets. Enable's transportation and storage assets also provide facilities where natural gas can be stored by customers.

Enable's interstate and intrastate natural gas transportation and storage systems generate revenue primarily by serving large natural gas and electric utilities, as well as natural gas producers, industrial end-users and natural gas marketers. For the year ended December 31, 2020, approximately 28 percent of EGT's service revenue was attributable to contracts with one customer, CenterPoint. As of December 31, 2020, EGT's transportation contracts representing three percent, eight percent and 89 percent of CenterPoint's firm transportation capacity are scheduled to expire in 2021, 2024 and 2030, respectively. EGT's firm storage contracts representing 33 percent and 67 percent of CenterPoint's firm storage capacity are scheduled to expire in 2021 and 2030, respectively.
For the year ended December 31, 2020, approximately 63 percent of MRT's service revenue was attributable to contracts with one customer, Spire Inc. MRT's firm transportation contracts representing 63 percent, 24 percent and 12 percent of Spire Inc.'s firm transportation capacity are scheduled to expire in 2024, 2025 and 2026, respectively. All of Spire Inc.'s firm storage contracts are scheduled to expire in 2024.

Enable's EGT, MRT and SESH transportation and storage services are typically provided under firm, fee-based transportation and storage agreements, with rates and terms of service regulated by the FERC. EOIT provides fee-based firm and interruptible transportation and storage services on both an intrastate and interstate basis.

Enable's interstate and intrastate pipelines compete with a variety of other interstate and intrastate pipelines in providing transportation and storage services within its operating areas. Enable's management views the principal elements of competition for their natural gas transportation and storage systems primarily as a function of rates, terms of services, flexibility and reliability.

Customer demand for natural gas transportation and storage services on EGT and MRT is usually higher during the winter, primarily due to LDC demand to serve residential and commercial natural gas requirements. Customer demand for natural gas transportation and storage services on EOIT and SESH is usually higher during the summer, primarily due to electric utility demand for natural gas.

Environmental Matters
 
General
 
The activities of the Registrants are subject to numerous stringent and complex federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact the Registrants' business activities in many ways, including the handling or disposal of waste material, planning for future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions or pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of the Registrants' operations are in substantial compliance with current federal, state and local environmental standards.
In the past, environmental regulation caused the Registrants to incur significant costs because the trend was to place more and more restrictions and limitations on the Registrants' activities. Under the Trump administration, the trend in environmental regulation was to delay, reverse or repeal some of these restrictions and generally not to adopt new, more stringent regulations. The Biden administration has announced that it plans to reverse many of the Trump administration's environmental policies, including issuance of an executive order that instructs the EPA and other executive agencies to review certain rules that affect the Registrants. The Registrants are monitoring these actions in an effort to understand the likely stringency of future rules. In the meantime, the Registrants continue to have obligations to take or complete action under current environmental rules.



12

Management continues to evaluate the Registrants' compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market but at the current time, based on existing rules, does not expect capital expenditures for environmental control facilities to be material for 2021 or 2022. For further discussion of environmental matters and capital expenditures related to environmental factors that may affect the Registrants, see "2020 Capital Requirements, Sources of Financing and Financing Activities," "Future Capital Requirements" and "Environmental Laws and Regulations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

Human Capital Management

Our company fulfills a critical role in the nation's electric utility and, through our equity investment in Enable, natural gas midstream pipeline infrastructure. In order to do so, we believe we need to attract, retain and develop a high quality, diverse workforce and create a safe, inclusive and productive work environment for everyone. We believe that our company's core values and beliefs, including those of respect, diversity and inclusion, and safety, serve as a foundation for our relationships with our employees, who we refer to internally as "members" of the Registrants. These core values and beliefs are reinforced to all employees at the time of hire, annually through a review of our Code of Ethics and periodically through small and large group meetings. At December 31, 2020, OGE Energy had 2,360 employees, of which 1,872 are OG&E employees.

To help us attract and retain the most qualified individuals for our businesses, we provide a combination of strong compensation and health and welfare benefit offerings, growth and development opportunities and various retirement plan options. Our employees are also offered paid volunteer leave every year, which is intended to further enrich both their lives and the lives in the communities we serve. Many of the positions in our companies are highly specialized, so having appropriate training and succession planning is critical to business continuity and competitiveness. We provide leadership and career development opportunities, including internal and external training as well as tuition reimbursement, to invest in the next generation of leaders for our company. We target an average of 30-35 hours of training per employee annually, which aligns with the benchmark published annually by the American Society of Training and Development. This comprehensive investment in our employees contributes to an average tenure of 15 years and a voluntary turnover rate of 5.7 percent for 2020, which is 0.5 percent lower than the average voluntary turnover rate compared to our industry benchmark (the PwC Saratoga Benchmarking Service).

Employee safety is paramount in the work we perform. One of our company core beliefs is to "Live Safely," which to us means that we protect ourselves and others from injury by constant engagement, "always living safely." Our goal is to have zero safety incidents every year, and we educate all of our employees on our incident and injury free workplace vision. We report and analyze all near misses and incidents to understand the causal factors and associated corrective actions necessary to reduce the likelihood of reoccurrence. We share what we have learned company-wide to provide real-time learning opportunities for all employees. We track our safety performance and benchmark ourselves to our peer group, the Southeast Electric Exchange. For 2020, our Southeast Electric Exchange incident rate was 0.47, which represented a 40 percent improvement from our 2019 performance. The incident rate is calculated by counting the actual number of injuries and illnesses per 100 employees' standard base labor hours divided by the actual number of hours employees worked. In comparison to our peer group, our five year average safety performance placed us in the top quartile. We continue to analyze trends and engage in discussions with our employees, creating a dialogue to enhance safety performance and work towards our incident and injury-free workplace. Further discussion of the steps we are taking to help ensure employee safety during the COVID-19 pandemic can be found in "Item 7. Management's Discussion and Analysis – Recent Developments – COVID-19."

We also strive to reinforce the belief that our employees are one of our greatest assets by creating a culture of respect throughout the company. We do this by, among other things, encouraging employees to treat others justly and considering their views in the decisions we make. We believe diversity and inclusion means embracing the uniqueness of each individual to make us a stronger and more resourceful organization while serving and supporting the diverse communities where we live and work. We are focused on creating a more diverse and inclusive workforce, particularly related to minority hiring. We have formed relationships with diverse high schools in our service territory to introduce their students to potential jobs in the energy industry and career paths to OGE Energy and have worked with technical schools to recruit diverse students to their programs, which can lead to potential employment for our operational positions. We have also formed relationships with universities to provide scholarships to students with diverse backgrounds. Additionally, we have focused on hiring individuals transitioning out of the military. We are also focused on the inclusion of women in leadership positions. For example, female representation among our officers and management-level directors is currently at 27 percent, which is up eight percent compared to five years ago. As some of our more tenured employees retire (we average approximately 85 to 90 retirements, or four percent of our workforce, per year), opportunities are created to promote or attract and hire additional individuals with diverse backgrounds.


13

Another initiative intended to promote inclusion and member development is the establishment of Employee Resource Groups at the company, and our newly appointed Director of Ethics, Equity, and Inclusion is leading this effort.

Information About the Registrants' Executive Officers

The following table presents the names, titles and business experience for the most recent five years for those persons serving as Executive Officers of the Registrants as of February 24, 2021:
Name Age Current Title and Business Experience
Sean Trauschke 53 2016 - Present: Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp.
W. Bryan Buckler 48 2021: Chief Financial Officer of OGE Energy Corp.
2019 - 2020: Vice President of Investor Relations - Duke Energy Corporation
2016 - 2019: Director of Financial Planning and Analysis - Duke Energy Corporation
Sarah R. Stafford 39 2018 - Present: Controller and Chief Accounting Officer of OGE Energy Corp.
2016 - 2018: Accounting Research Officer of OGE Energy Corp.
2016: Senior Manager - Ernst & Young, LLP
Scott A. Briggs 49 2020 - Present: Vice President - Human Resources of OG&E
2019 - 2020: Managing Director Human Resources of OG&E
2016 - 2018: Chief Operating Officer of The Oklahoma Publishing Co., d/b/a The Oklahoma Media Company
Robert J. Burch 58 2020 - Present: Vice President - Utility Technical Services of OG&E
2018 - 2020: Managing Director Utility Technical Services of OG&E
2016 - 2018: Director Power Supply Services of OG&E
Andrea M. Dennis 44 2019 - Present: Vice President - Transmission and Distribution Operations of OG&E
2019: Managing Director Transmission and Distribution Operations of OG&E
2016 - 2019: Director System Operations of OG&E
Patricia D. Horn 62 2016 - Present: Vice President - Governance and Corporate Secretary of OGE Energy Corp.
Donnie O. Jones 54 2019 - Present: Vice President - Utility Operations of OG&E
2016 - 2019: Vice President - Power Supply Operations of OG&E
Cristina F. McQuistion 56 2020 - Present: Vice President - Corporate Responsibility and Stewardship of OGE Energy Corp.
2017 - 2020: Vice President - Chief Information Officer of OG&E
2016 - 2017: Vice President - Chief Information Officer and Utility Strategy of OG&E
Kenneth A. Miller 54 2019 - Present: Vice President - Regulatory and Legislative Affairs of OG&E
2016 - 2018: State Treasurer of Oklahoma
David A. Parker 44 2020 - Present: Vice President - Technology, Data and Security of OG&E
2019 - 2020: Director Enterprise Security & Risk of OGE Energy Corp.
2016 - 2019: Director of Internal Audit of OGE Energy Corp.
Matthew J. Schuermann 41 2020 - Present: Vice President - Power Supply Operations of OG&E
2019 - 2020: Managing Director Power Plant Operations of OG&E
2016 - 2019: Special Projects Director of OG&E
William H. Sultemeier 53 2017 - Present: General Counsel and Chief Compliance Officer of OGE Energy Corp.
2016: Partner - Jones Day
Charles B. Walworth 46 2016 - Present: Treasurer of OGE Energy Corp.

No family relationship exists between any of the Executive Officers of the Registrants. Messrs. Trauschke, Buckler, Sultemeier, Walworth and Mses. Horn, McQuistion and Stafford are also officers of OG&E. Each Executive Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Shareholders, currently scheduled for May 20, 2021.



14

Mr. Trauschke is a member of the Board of Directors of Enable GP, LLC, the general partner of Enable. In October 2020, Ms. Stafford and Mr. Walworth were appointed as alternate directors of the Board of Enable GP, LLC.

Item 1A. Risk Factors.

In the discussion of risk factors set forth below, unless the context otherwise requires, the terms "we," "our" and "us" refer to the Registrants. In addition to the other information in this Form 10-K and other documents filed by us and/or our subsidiaries with the Securities and Exchange Commission from time to time, the following factors should be carefully considered in evaluating OGE Energy and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on behalf of us or our subsidiaries. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.

The Registrants are subject to a variety of risks which can be classified as regulatory, operational, financial and general. Risk factors of OG&E are also risk factors of OGE Energy. OGE Energy also is subject to risks associated with its investment in Enable.

REGULATORY RISKS

The Registrants' profitability depends to a large extent on the ability of OG&E to fully recover its costs, including its cost of capital, from its customers in a timely manner, and there may be changes in the regulatory environment that impair its ability to recover costs from its customers.
 
OG&E is subject to comprehensive regulation by several federal and state utility regulatory agencies, which significantly influences its operating environment and its ability to fully recover its costs, including its cost of capital, from utility customers. Recoverability of any under recovered amounts from OG&E's customers due to a rise in fuel costs is a significant risk, such as experienced in February 2021 due to the unprecedented, prolonged, cold spell that resulted in winter record winter peak demand for electricity in OG&E's service territory and extreme natural gas and purchased power prices. The utility commissions in the states where OG&E operates regulate many aspects of its utility operations including siting and construction of facilities, customer service and the rates that OG&E can charge customers. The profitability of the utility operations is dependent on OG&E's ability to fully recover costs related to providing energy and utility services to its customers in a timely manner. Any failure to obtain utility commission approval to increase rates to fully recover costs, or a delay in the receipt of such approval, could have an adverse impact on OG&E's results of operations. In addition, OG&E's jurisdictions have fuel adjustment clauses that permit OG&E to recover fuel costs through rates without a general rate review, subject to a later determination that such fuel costs were prudently incurred. If the state regulatory commissions determine that the fuel costs were not prudently incurred, recovery could be disallowed. See Note 16 within "Item 8. Financial Statements and Supplementary Data" for further discussion of the significant fuel and purchased power costs incurred during the February 2021 weather event and the related regulatory filing with the OCC.
 
In recent years, the regulatory environments in which OG&E operates have received an increased amount of attention. It is possible that there could be changes in the regulatory environment that would impair OG&E's ability to fully recover costs historically paid by OG&E's customers. State utility commissions generally possess broad powers to ensure that the needs of the utility customers are being met. OG&E cannot assure that the OCC, APSC and the FERC will grant rate increases in the future or in the amounts requested, and they could instead lower OG&E's rates.
 
The Registrants are unable to predict the impact on their operating results from future regulatory activities of any of the agencies that regulate OG&E. Changes in regulations or the imposition of additional regulations could have an adverse impact on the Registrants' results of operations.

OG&E's rates are subject to rate regulation by the states of Oklahoma and Arkansas, as well as by a federal agency, whose regulatory paradigms and goals may not be consistent.
 
OG&E is a vertically integrated electric utility. Most of its revenue results from the sale of electricity to retail customers subject to bundled rates that are approved by the applicable state utility commission.

OG&E operates in Oklahoma and western Arkansas and is subject to rate regulation by the OCC and the APSC, in addition to FERC regulation of its transmission activities and any wholesale sales. Exposure to inconsistent state and federal regulatory standards may limit our ability to operate profitably. Further alteration of the regulatory landscape in which we operate, including a change in our authorized return on equity, may harm our financial position and results of operations.


15

 
Costs of compliance with environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, financial position or liquidity.
 
We are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities or the use of certain fuels required for the production of electricity and/or require additional pollution control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future. 
 
In response to recent regulatory and judicial decisions and international accords, emissions of greenhouse gases including, most significantly, CO2, could be restricted in the future as a result of federal or state legal requirements or litigation relating to greenhouse gas emissions. No rules are currently in effect that require us to reduce our greenhouse gas emissions, but if such rules were to become effective, they could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

There is inherent risk of the incurrence of environmental costs and liabilities in our operations and historical industry practices. These activities are subject to stringent and complex federal, state and local laws and regulations that can restrict or impact OG&E's business activities in many ways, such as restricting the way OG&E can handle or dispose of its wastes or requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators. OG&E may be unable to recover these costs from insurance or other regulatory mechanisms. We expect that the Biden administration will enact stricter laws, regulations and enforcement policies that could significantly increase compliance costs and the cost of any remediation that may become necessary. If regulations are enacted regarding any of our generating units, it could potentially result in stranded assets.

For further discussion of environmental matters that may affect the Registrants, see "Environmental Laws and Regulations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

We may not be able to recover the costs of our substantial investments in capital improvements and additions.
 
Our business plan calls for extensive investments in capital improvements and additions in OG&E, including modernizing existing infrastructure as well as other initiatives. Significant portions of OG&E's facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with environmental requirements or to provide reliable operations. OG&E currently provides service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates OG&E charges, it would not be able to recover the costs associated with its planned extensive investment. This could adversely affect the Registrants' financial position and results of operations. While OG&E may seek to limit the impact of any denied recovery by attempting to reduce the scope of its capital investment, there can be no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.
 
The regional power market in which OG&E operates has changing transmission regulatory structures, which may affect the transmission assets and related revenues and expenses.

OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority (but not ownership) of OG&E's transmission facilities to the SPP. The SPP has implemented regional day ahead and real-time markets for energy and operating reserves, as well as associated transmission congestion rights. Collectively, the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities. We record the SPP Integrated Marketplace transactions as sales or purchases with results reported as Revenues from Contracts with Customers or Cost of Sales in its financial statements. Our revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation of the SPP Integrated Marketplace by the FERC or the SPP.



16

Increased competition resulting from efforts to restructure utility and energy markets could have a significant financial impact on us and consequently impact our revenue.
 
We have been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes have occurred and additional changes have been proposed to the wholesale electric market. Although retail restructuring efforts in Oklahoma and Arkansas have been postponed for the time being, if such efforts were renewed, retail competition and the unbundling of regulated energy service could have a significant financial impact on us due to possible impairments of assets, a loss of retail customers, impact profit margins and/or increased costs of capital. Any such restructuring could have a significant impact on our financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our financial position, results of operations or cash flows.
 
We are subject to substantial utility and energy regulation by governmental agencies. Compliance with current and future utility and energy regulatory requirements and procurement of necessary approvals, permits and certifications may result in significant costs to us.
 
We are subject to substantial regulation from federal, state and local regulatory agencies. We are required to comply with numerous laws and regulations and to obtain permits, approvals and certifications from the governmental agencies that regulate various aspects of our businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices and the operation of generating facilities. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of these agencies.
 
The NERC is responsible for the development and enforcement of mandatory reliability and cyber security standards for the wholesale electric power system. OG&E's plan is to comply with all applicable standards and to expediently correct a violation should it occur. As one of OG&E's regulators, the NERC has comprehensive regulations and standards related to the reliability and security of our operating systems and is continuously developing additional mandatory compliance requirements for the utility industry. The increasing development of NERC rules and standards will increase compliance costs and our exposure for potential violations of these standards.

OPERATIONAL RISKS 

Our results of operations may be impacted by disruptions to fuel supply or the electric grid that are beyond our control.
 
We are exposed to risks related to performance of contractual obligations by our suppliers. We are dependent on coal and natural gas for much of our electric generating capacity. We rely on suppliers to deliver coal and natural gas in accordance with short- and long-term contracts. We have certain supply contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal and natural gas to us. The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us. In addition, the suppliers under these agreements may not be required to supply coal and natural gas to us under certain circumstances, such as in the event of a natural disaster. Deliveries may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather and availability of equipment. Failure or delay by our suppliers of coal and natural gas deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers.
 
Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event such as a severe storm, generator or transmission facility outage on a neighboring system or the actions of a neighboring utility. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial position, results of operations and cash flows.
 
OG&E's electric generation, transmission and distribution assets are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, increased purchase power costs, accidents and third-party liability.  

OG&E owns and operates coal-fired, natural gas-fired, wind-powered and solar-powered generating assets. Operation of electric generation, transmission and distribution assets involves risks that can adversely affect energy output and efficiency


17

levels or that could result in loss of human life, significant damage to property, environmental pollution and impairment of OG&E's operations. Included among these risks are:

•increased prices for fuel and fuel transportation as existing contracts expire;
•facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply;
•operator error or safety related stoppages;
•disruptions in the delivery of electricity; and
•catastrophic events such as fires, explosions, tornadoes, floods, earthquakes or other similar occurrences.

The occurrence of any of these events, if not fully covered by insurance, could have a material effect on our financial position and results of operations. Further, when unplanned maintenance work is required on power plants or other equipment, OG&E will not only incur unexpected maintenance expenses, but it may also have to make spot market purchases of replacement electricity that could exceed OG&E's costs of generation or be forced to retire a generation unit if the cost or timing of the maintenance is not reasonable and prudent. If OG&E is unable to recover any of these increased costs in rates, it could have a material adverse effect on our financial performance.

 Changes in technology, regulatory policies and customer electricity consumption may cause our assets to be less competitive and impact our results of operations.

OG&E primarily generates electricity at large central facilities. This method typically results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies or changes in regulatory policies will reduce costs of new technology to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations. OG&E's widespread use of Smart Grid technology allowing for two-way communications between the utility and its customers could enable the entry of technology companies into the interface between OG&E and its customers, resulting in unpredictable effects on our current business.

Reductions in customer electricity consumption, thereby reducing utility electric sales, could result from increased deployment of renewable energy technologies as well as increased efficiency of household appliances, among other general efficiency gains in technology. However, this potential reduction in load would not reduce our need for ongoing investments in our infrastructure to reliably serve our customers. Continued utility infrastructure investment without increased electricity sales could cause increased rates for customers, potentially resulting in further reductions in electricity sales and reduced profitability.

Weather conditions such as tornadoes, thunderstorms, ice storms, wind storms, flooding, earthquakes, prolonged droughts and the occurrence of wildfires, as well as seasonal temperature variations may adversely affect our financial position, results of operations and cash flows.
 
Weather conditions directly influence the demand for electric power. In OG&E's service area, demand for power peaks during the hot summer months, with market prices also typically peaking at that time. As a result, overall operating results may fluctuate on a seasonal and quarterly basis. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Unusually mild weather in the future could reduce our revenues, net income, available cash and borrowing ability. Severe weather, such as tornadoes, thunderstorms, ice storms, wind storms, flooding, earthquakes, prolonged droughts and the occurrence of wildfires, may cause outages and property damage which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned, as described above, would be particularly burdensome during a peak demand period. In addition, prolonged droughts could cause a lack of sufficient water for use in cooling during the electricity generating process. Additionally, if climate change exacerbates physical changes in weather, operations may be impacted as discussed above. OG&E can incur significant restoration costs as a result of these weather events. If OG&E is unable to recover any of these increased costs in rates, it could have a material adverse effect on our financial performance.

FINANCIAL RISKS

Market performance, increased retirements, changes in retirement plan regulations and increasing costs associated with our Pension Plan, health care plans and other employee-related benefits may adversely affect our financial position, results of operations or cash flows.
 
We have a Pension Plan that covers a significant amount of our employees hired before December 1, 2009. We also have defined benefit postretirement plans that cover a significant amount of our employees hired prior to February 1,


18

2000. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our results of operations and funding requirements. Based on our assumptions at December 31, 2020, we expect to make future contributions to maintain required funding levels. It has been our practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. We may continue to make voluntary contributions in the future. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.
 
If the employees who participate in the Pension Plan retire when they become eligible for retirement over the next several years, or if our plan experiences adverse market returns on its investments, or if interest rates materially fall, our pension expense and contributions to the plans could rise substantially over historical levels. The timing and number of employees retiring and selecting the lump-sum payment option could result in pension settlement charges that could materially affect our results of operations if we are unable to recover these costs through our electric rates. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on our financial position and results of operations. Those factors are outside of our control.
 
In addition to the costs of our Pension Plan, the costs of providing health care benefits to our employees and retirees have increased in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees, will continue to rise. The increasing costs and funding requirements with our Pension Plan, health care plans and other employee benefits may adversely affect our financial position, results of operations or liquidity.

Finally, OGE Energy provides retirement benefits and retiree health care benefits to 76 employees seconded to Enable. If the seconding agreement was terminated, and those employees were no longer employed by OGE Energy, and lump sum payments were made to those employees, OGE Energy would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at OGE Energy by $19.0 million. Settlement and curtailment charges associated with the Enable seconded employees are not reimbursable to OGE Energy by Enable. The seconding agreement can be terminated by mutual agreement of OGE Energy and Enable or solely by OGE Energy upon 120 days' notice. Assuming the pending merger between Enable and Energy Transfer is completed, the seconding agreement will be terminated.
 
OGE Energy is a holding company with its primary assets being investments in its subsidiary and equity investments.
 
OGE Energy is a holding company and thus its investments in its subsidiary and unconsolidated affiliate, accounted for under the equity method, are its primary assets. Substantially all of OGE Energy's operations are conducted by its subsidiary and unconsolidated affiliate. Consequently, OGE Energy's operating cash flow and its ability to pay dividends and service its indebtedness utilizes the operating cash flow of its subsidiary and unconsolidated affiliate and the payment of funds by them to OGE Energy in the form of dividends or distributions. At December 31, 2020, OGE Energy and OG&E had outstanding indebtedness and other liabilities of $7.1 billion. OGE Energy's subsidiary, OG&E, and unconsolidated affiliate, Enable, are separate legal entities that have no obligation to pay any amounts due on OGE Energy's indebtedness or to make any funds available for that purpose, whether by dividends or otherwise. In addition, their ability to pay dividends to OGE Energy depends on any statutory and contractual restrictions that may be applicable to such subsidiary, which may include requirements to maintain minimum levels of working capital and other assets. Claims of creditors, including general creditors, of OGE Energy's subsidiary or unconsolidated affiliate on their respective assets will generally have priority over OGE Energy claims (except to the extent that OGE Energy may be a creditor of the subsidiaries and its claims are recognized) and claims by OGE Energy shareholders.
 
In addition, as discussed above, OG&E is regulated by state utility commissions in Oklahoma and Arkansas as well as a federal regulatory agency which generally possess broad powers to ensure that the needs of the utility customers are being met. To the extent that the state commissions or federal regulatory agency attempt to impose restrictions on the ability of OG&E to pay dividends to OGE Energy, it could adversely affect its ability to continue to pay dividends.

RISKS ASSOCIATED WITH OGE ENERGY'S INVESTMENT IN ENABLE

OGE Energy does not control Enable and therefore is not able to cause or prevent certain actions by Enable. The general partnership of Enable is equally controlled by OGE Energy and CenterPoint.

Enable has its own governing board; therefore, OGE Energy is not able to exercise control over Enable. Accordingly, OGE Energy is unable to cause or prevent certain actions by Enable. Further, OGE Energy cannot control the actions of the other general partner, CenterPoint. OGE Energy's interests may not align with those of CenterPoint, and this lack of control could adversely impact its investment in Enable.



19

As discussed in "Item 1. Business," in February 2021, Enable entered into a definitive merger agreement with Energy Transfer. Assuming the transaction closes, OGE Energy will own approximately three percent of Energy Transfer's outstanding limited partner units in lieu of the 25.5 percent interest in Enable that it currently owns, which would result in OGE Energy having less control over the activities of its expected investment in Energy Transfer. Further, although OGE Energy does not control Enable, OGE Energy has a 50 percent interest in Enable's general partner and is able to designate two directors for the Enable board. Following completion of the merger, OGE Energy will not have any interest in the general partner and will not have any designees on the Energy Transfer board. Accordingly, OGE Energy will be unable to cause, prevent or influence actions by Energy Transfer.

A portion of OGE Energy's earnings and operating cash flows are based on the performance of Enable. If any of the following risks were to occur, OGE Energy's business, financial condition, results of operations or cash flows could be materially adversely affected.

OGE Energy's operating cash flow is derived partially from cash distributions it receives from Enable.

OGE Energy's operating cash flow is derived partially from cash distributions it receives from Enable. The amount of cash Enable can distribute on its units principally depends upon the amount of cash generated from its operations, which will fluctuate from quarter to quarter based on, among other things:

•the fees and gross margins it realizes with respect to the volume of natural gas, NGLs and crude oil that it handles;
•the prices of, levels of production of, and demand for natural gas, NGLs and crude oil;
•the volume of natural gas, NGLs and crude oil it gathers, compresses, treats, dehydrates, processes, fractionates, transports and stores;
•the relationship among prices for natural gas, NGLs and crude oil;
•cash calls and settlements of hedging positions;
•margin requirements on open price risk management assets and liabilities;
•the level of competition from other companies offering midstream services;
•adverse effects of governmental and environmental regulation;
•the level of its operation and maintenance expenses and general and administrative costs; and
•prevailing economic conditions.

In addition, the actual amount of cash Enable will have available for distribution will depend on other factors, including:

•the level and timing of capital expenditures it makes;
•the cost of acquisitions;
•its debt service requirements and other liabilities;
•fluctuations in working capital needs;
•its ability to borrow funds and access capital markets;
•restrictions contained in its debt agreements;
•the amount of cash reserves established by its general partner;
•distributions paid on its Series A Preferred Units; and
•other business risks affecting its cash levels.

Enable's contracts are subject to renewal risks.

As contracts with Enable's existing suppliers and customers expire, Enable generally seeks to negotiate extensions or renewals of those contracts or enters into new contracts with other suppliers and customers. Enable may be unable to extend or renew existing contracts or enter into new contracts on favorable commercial terms, if at all. Depending on prevailing market conditions at the time of an extension or renewal, gathering and processing customers with fee-based contracts may desire to enter into contracts under different fee arrangements, and gathering and processing customers with contracts that contain minimum volume commitments may desire to enter into contracts without minimum volume commitments. Likewise, Enable's transportation and storage customers may choose not to extend or renew expiring contracts based on the economics of the related areas of production. To the extent Enable is unable to renew or replace its expiring contracts on terms that are favorable to Enable, if at all, or successfully manage its overall contract mix over time, its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy, could be adversely affected.



20

The businesses of Enable are dependent, in part, on the drilling and production decisions of others. In response to sharp declines in demand for oil and gas as well as commodity prices resulting from the economic impact of the COVID-19 pandemic, many producers have significantly reduced previously anticipated drilling and production activities and may make additional reductions in the future.

The businesses of Enable are dependent on the drilling and production of natural gas and crude oil. Enable has no control over the level of drilling activity in its areas of operation, or the amount of natural gas, NGLs and crude oil reserves associated with wells connected to its systems, or the amount of natural gas, NGLs and crude oil produced from the wells connected to its systems. In addition, as the rate at which production from wells currently connected to its system naturally declines over time, its gross margin associated with those wells will also decline. To maintain or increase throughput levels on its gathering and transportation systems and the asset utilization rates at its natural gas processing plants, its customers must continually obtain new natural gas, NGLs and crude oil supplies. Drilling activity in the areas served by our systems significantly impacts Enable's ability to obtain new volumes of natural gas, NGLs and crude oil on its systems. If Enable is not able to obtain new volumes of natural gas, NGLs and crude oil to replace the natural decline in volumes from existing wells, throughput on its gathering, processing, transportation and storage facilities would decline, which could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy. Enable has no control over producers or their drilling and production decisions, which are affected by, among other things:

•the availability and cost of capital;
•prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;
•demand for natural gas, NGLs and crude oil;
•levels of reserves;
•geological considerations;
•global or national health events, including epidemics and pandemics such as the ongoing COVID-19 pandemic;
•environmental or other governmental regulations, including the availability of drilling permits, the regulation of hydraulic fracturing and the regulation of air emissions; and
•the availability of drilling rigs and other costs of production and equipment.

Fluctuations in energy prices can also greatly affect the development of new natural gas, NGLs and crude oil reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, NGLs, crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond its control. Because of these and other factors, even if new reserves are known to exist in areas served by Enable's assets, producers may choose not to develop those reserves. Declines in natural gas, NGLs or crude oil prices can have a negative impact on exploration, development and production activity and, if sustained, could lead to decreases in such activity. For instance, the recent COVID-19 pandemic has adversely affected Enable's business by (i) reducing the demand for natural gas, NGLs and crude oil due to reduced global and national economic activity, leading to significantly lower prices for natural gas, NGLs and crude oil, (ii) impairing the supply chain of certain Enable customers for which it provides gathering and processing services, which could lead to further reduction of the utilization of Enable's systems, and (iii) reducing producer activity across Enable's footprint, which is expected to continue to result in reduced utilization of its services. Enable currently cannot predict the duration or magnitude of the effects of the COVID-19 pandemic on supply and demand for natural gas, NGLs and crude oil or the exploration, development and production activity of the producers across its areas of operation. In addition, concerns about global economic growth, as well as uncertainty regarding the timing, pace and extent of an economic recovery in the U.S. and abroad, have had a significant adverse impact on global financial markets and commodity prices, and sustained low natural gas, NGLs or crude oil prices could also lead producers to shut in production from their existing wells. Sustained reductions in exploration or production activity in its areas of operation could lead to further reductions in the utilization of its systems, which could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including OGE Energy, and result in the impairment of its assets.

In addition, it may be more difficult to maintain or increase the current volumes on its gathering systems and in its processing plants, as several of the formations in the unconventional resource plays in which Enable operates generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should Enable determine that the economics of its gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, it may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time.



21

Enable's industry is highly competitive and increased competitive pressure could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

Enable competes with other midstream service providers in its areas of operation. The principal elements of competition for both gathering and processing services and transportation and storage services are rates, terms of service, flexibility and reliability. Competitors include other midstream service providers, including those affiliated with producers, that may have greater financial resources or greater access to new volumes of natural gas, NGLs and crude oil than Enable does. Some of these competitors may create additional competition by expanding existing or constructing new gathering, processing, transportation and storage systems. Enable's producer customers may become competitors by developing their own midstream systems. Excess gathering, processing, transportation or storage capacity in the areas Enable serves may increase competitive pressure by decreasing rates and adversely impact the ability to renew existing or enter into new contracts. Natural gas, NGLs and crude oil used as or to produce fuel compete with other forms of energy, including electricity and coal. Increased demand for one form of energy over another could lead to a reduction in demand for associated midstream services. All of these competitive pressures could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

Natural gas, NGLs and crude oil prices are volatile, and changes in these prices could adversely affect Enable's financial position, results of operations and its ability to make cash distributions to unitholders, including OGE Energy. Prices for all three of these commodities have been adversely affected by the impact of the COVID-19 pandemic, with crude oil prices reaching historic lows in April 2020.

Enable's financial position, results of operations and ability to make cash distributions to OGE Energy could be negatively affected by adverse changes in the prices of natural gas, NGLs and crude oil depending on factors that are beyond its control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, liquefied natural gas, NGLs and crude oil, actions taken by foreign natural gas and oil producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption, global or national health concerns and the extent of governmental regulation and taxation. For example, the price of, and demand for, natural gas, NGLs and crude oil declined significantly in response to the ongoing spread and economic effects of the COVID-19 pandemic, including significant governmental measures being implemented to control the spread of the virus, including quarantines, travel restrictions and business shutdowns and Russia's March 2020 rejection of a plan backed by Saudi Arabia and other members of OPEC to reduce production of crude oil in response to declining global demand. Following the rejection of the plan, Saudi Arabia significantly reduced the prices at which it sells crude oil, and both Saudi Arabia and Russia announced plans to increase production. While a coalition of 23 nations led by Saudi Arabia and Russia subsequently agreed to reduce production of crude oil by 9.7 million barrels per day in May and June of 2020, NGLs and crude oil prices have remained depressed. These events, combined with the continuing COVID-19 pandemic and uncertainty regarding the length of time it will take for the U.S. and the rest of the world to slow the spread of COVID-19 to the point where applicable authorities are comfortable easing current restrictions on various commercial and economic activities, contributed to a sharp drop in prices for crude oil in the first and second quarters of 2020.

Enable's natural gas processing arrangements expose Enable to commodity price fluctuations. In 2020, 6 percent, 33 percent and 61 percent of Enable's processing plant inlet volumes consisted of keep-whole arrangements, percent-of-proceeds or percent-of-liquids and fee-based, respectively. If the price at which Enable sells natural gas or NGLs is less than the cost at which it purchases natural gas or NGLs under these arrangements, then its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy, could be adversely affected. Enable uses certain derivative instruments to manage its commodity price risk exposures.

At any given time, Enable's overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that it is a net buyer of natural gas) and a net long position in NGLs (meaning that it is a net seller of NGLs). As a result, Enable's financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy, could be adversely affected to the extent the price of NGLs decreases in relation to the price of natural gas.

A pandemic, epidemic or outbreak of an infectious disease, such as the COVID-19 pandemic, may materially adversely affect Enable's business.

A global or national pandemic, such as COVID-19, may cause disruptions to Enable's business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies


22

from third parties upon which Enable relies, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines, travel restrictions and business shutdowns, to address the COVID-19 pandemic and (v) restrictions that Enable and its contractors and subcontractors impose, including facility shutdowns, to ensure the safety of employees and others. For example, many of Enable's employees have been temporarily required to work remotely which may disrupt Enable's operations or increase the risk of a cybersecurity incident. While it is not possible to predict their extent or duration, these disruptions may have a material adverse effect on Enable's business, financial condition and results of operations.

The effects of the COVID-19 pandemic and concerns regarding its continued global spread have negatively impacted domestic and international demand for natural gas, NGLs and crude oil, which has and could continue to contribute to price volatility and materially and adversely affect Enable's customers' operations and future production, resulting in less demand for Enable's services and/or the reduction of commercial opportunities that might otherwise be available to Enable. The effects of the COVID-19 pandemic have also negatively impacted domestic and international economic conditions, which has and could continue to contribute to price declines and volatility in the financial markets. While it is not possible to predict their extent or duration, these economic conditions could materially and adversely affect the availability of debt or equity financing to Enable, which may result in a significant reduction of Enable's liquidity.

Enable provides certain transportation and storage services under fixed-price "negotiated rate" contracts that are not subject to adjustment, even if the cost to perform such services exceeds the revenues received from such contracts, and, as a result, costs could exceed revenues received under such contracts.

Enable has been authorized by the FERC to provide transportation and storage services at its facilities at negotiated rates. As of December 31, 2020, approximately 37 percent of Enable's aggregate contracted firm transportation capacity on EGT and MRT and 52 percent of its aggregate contracted firm storage capacity on EGT and MRT was subscribed under such "negotiated rate" contracts. These contracts generally do not include provisions allowing for adjustment for increased costs due to inflation, pipeline safety activities or other factors that are not tied to an applicable tracking mechanism authorized by the FERC. Successful recovery of any shortfall of revenue, representing the difference between "recourse rates" (if higher) and negotiated rates, is not assured under current FERC policies. If Enable's costs increase and it is not able to recover any shortfall of revenue associated with its negotiated rate contracts, the cash flow realized by its systems could decrease and, therefore, the cash Enable has available for distribution to its unitholders, including OGE Energy, could also decrease.

If third-party pipelines and other facilities interconnected to Enable's gathering, processing or transportation facilities become partially or fully unavailable to Enable for any reason, Enable's financial position, results of operations and its ability to make cash distributions to unitholders, including OGE Energy, could be adversely affected.

Enable depends upon (i) third-party pipelines to deliver natural gas to, and take natural gas from, its natural gas transportation systems, (ii) third-party pipelines and other facilities to take crude oil, condensate and produced water from its crude oil, condensate and produced water gathering systems, and, in some cases, (iii) third-party facilities to process natural gas from its gathering systems. It also depends on third-party facilities to transport and fractionate NGLs that are delivered to the third party at the tailgates of its processing plants. Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale. An outage or disruption on certain pipelines or fractionators operated by a third party could result in the shutdown of certain of Enable's processing plants and gathering systems, and a prolonged outage or disruption could ultimately result in a reduction in the volume of natural gas Enable gathers and NGLs it is able to produce. For example, substantially all of the crude oil gathered by Enable's Williston Basin systems is delivered indirectly for transport to the Dakota Access Pipeline. Although the crude oil gathered by Enable's Williston Basin crude oil systems may also be delivered for transport to other pipelines, such as BakkenLink Pipeline and Enbridge North Dakota Pipeline, a shutdown of Dakota Access Pipeline, or any other significant pipeline providing transportation services from the Williston Basin, could result in the shut-in of wells connected to Enable's Williston Basin crude oil systems if its customers are unable to obtain sufficient capacity on those pipelines at an effective cost. In July 2020, the federal district court for the District of Columbia vacated the U.S. Army Corps of Engineers' grant of an easement to Dakota Access Pipeline and issued an order requiring Dakota Access Pipeline to be shut down and emptied of crude oil by August 5, 2020, pending the completion of an environmental impact analysis for the pipeline. In January 2021, the U.S. Court of Appeals for the DC Circuit affirmed the district court's decision that the Corps of Engineers did not follow proper procedures to grant the easement but reversed the district court's order requiring the pipeline to shut down. It can continue operating while the Corp of Engineers attempts to cure the defects identified by the district court. Additionally, Enable depends on third parties to provide electricity for compression, pumping and other operational activities at many of its facilities. Since it does not own or operate any of these third-party pipelines or other facilities, continuing operation of those facilities is not within its control. If any of these third-party pipelines or other facilities become partially or fully unavailable to Enable for any reason, its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy, could be adversely affected.


23


Enable does not own all of the land on which its pipelines and facilities are located, which could disrupt its operations.

Enable does not own all of the land on which its pipelines and facilities have been constructed, and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate. Enable may obtain the rights to construct and operate its pipelines for a specific period of time on lands owned by governmental agencies, American Indian tribes or other third parties, including on American Indian allotments, title to which is held in trust by the U.S. A loss of these rights, through its inability to renew right-of-way contracts or otherwise, could cause a cease in operations temporarily or permanently on the affected land, increase costs related to the construction and continuing operations elsewhere, and adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

An impairment of long-lived assets, including intangible assets or equity method investments could reduce Enable's earnings.

Long-lived assets, including intangible assets with finite useful lives and property, plant and equipment, are evaluated for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment of long-lived assets is recognized if the carrying amount is not recoverable and exceeds fair value. Due to decreases in natural gas and NGL market prices during 2020 as a result of the economic effects of the ongoing COVID-19 pandemic, together with the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, as of March 31, 2020, Enable reassessed the carrying value of the Atoka assets, in which it owns a 50 percent interest in the consolidated joint venture, which is a component of Enable's gathering and processing segment. Based on forecasted future undiscounted cash flows, Enable determined that the carrying value of the Atoka assets were not fully recoverable and recognized a $16 million impairment for the year ended December 31, 2020.

Equity method investments are evaluated for impairment when events or circumstances indicate that the carrying value of the investment might not be recoverable. An impairment of an equity method investment is recognized if the fair value of the investment as a whole, and not the underlying assets, has declined and the decline is other than temporary. An example of an investment that Enable accounts for under the equity method is its investment in SESH. If Enable enters into additional joint ventures, it could have additional equity method investments. At September 30, 2020, Enable estimated the fair value of its investment in SESH was below the carrying value and concluded the decline in value was other than temporary due to the expiration of a transportation contract and then current status of renewal negotiations. As a result, Enable recorded a $225 million impairment on its investment in SESH for the year ended December 31, 2020.

Enable could experience future events or circumstances that result in an impairment of long-lived assets, including intangible assets, equity method investments, or goodwill. If Enable recognizes an impairment, it would take an immediate non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. As a result, an impairment could have an adverse effect on Enable's results of operations and its ability to satisfy the financial ratios or other covenants under its existing or future debt agreements.

Enable's business involves many hazards and operational risks, some of which may not be fully covered by insurance. Insufficient insurance coverage and increased insurance costs could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

Enable's operations are subject to all of the risks and hazards inherent in the gathering, processing, transportation and storage of natural gas and crude oil, including:

•damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes and other natural disasters, acts of terrorism and actions by third parties;
•inadvertent damage from construction, vehicles and farm and utility equipment;
•leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas, NGLs and crude oil as a result of the malfunction of equipment or facilities;
•ruptures, fires and explosions; and
•other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property, plant and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of its operations. A natural disaster or other hazard affecting the areas in which it operates could adversely affect Enable's results of operations. Enable is not fully insured against all risks inherent in its business. Enable currently has general


24

liability and property insurance in place to cover certain of its facilities in amounts that it considers appropriate. Such policies are subject to certain limits and deductibles. Enable has business interruption insurance coverage for some but not all of its operations. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of Enable's facilities may not be sufficient to restore the loss or damage without adversely affecting its financial position, results of operations and ability to make cash distributions to its unitholders, including OGE Energy.

The use of derivative contracts by Enable and its subsidiaries in the normal course of business could result in financial losses that could adversely affect its financial position, results of operations and its ability to make cash distributions to unitholders, including OGE Energy.

Enable and its subsidiaries periodically use derivative instruments, such as swaps, options, futures and forwards, to manage its commodity and financial market risks. Enable and its subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

Failure to attract and retain an appropriately qualified workforce could adversely impact Enable's results of operations.

Enable's business is dependent on its ability to recruit, retain and motivate employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skill sets to future needs, competition for skilled labor or the unavailability of contract resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Enable's costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Enable's ability to manage and operate its business. If Enable is unable to successfully attract and retain an appropriately qualified workforce, its results of operations could be negatively affected.

As of December 31, 2020, Enable has 76 employees who are participants under OGE Energy defined benefit and retiree medical plans, who are seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. If seconding is terminated, employees of OGE Energy. that Enable determines to hire are under no obligation to accept Enable's offer of employment on the terms Enable provides, or at all.

Cybersecurity attacks or other disruptions of Enable's systems, networks and technology could adversely impact Enable's financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

Enable has become increasingly dependent on the systems, networks and technology that it uses to conduct almost all aspects of its business, including the operation of its gathering, processing, transportation and storage assets, the recording of commercial transactions and the reporting of financial information. Enable depends on both its own systems, networks and technology as well as the systems, networks and technology of its vendors, customers and other business partners. Any disruption of these systems, networks and technology could disrupt the operation of Enable's business. Disruptions can result from a variety of causes, including natural disasters, the failure of software or equipment and manmade events, such as cybersecurity attacks or information security breaches. Cybersecurity attacks and information security breaches could result in the unauthorized use of confidential, proprietary or other information and in the disruption of Enable's critical business functions and operations, adversely affecting its reputation and subjecting it to possible legal claims and liability. In addition, Enable is not fully insured against all cybersecurity risks.

As cybersecurity attacks continue to evolve, Enable may be required to expend significant additional resources to continue to modify or enhance its protective measures or to investigate and remediate any vulnerabilities to cybersecurity attacks. In particular, Enable's implementation of various procedures and controls to monitor and mitigate security threats and to increase security for its personnel, information, facilities and infrastructure may result in increased capital and operating costs. To date Enable has not experienced any material losses relating to cybersecurity attacks; however, there can be no assurance that it will not suffer such losses in the future. Consequently, it is possible that any of these occurrences, or a combination of them, could adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.



25

Terrorist attacks or other physical security threats could adversely affect Enable's business.

Enable's gathering, processing, transportation and storage assets may be targets of terrorist activities or other physical security threats that could disrupt its ability to conduct its business. It is possible that any of these occurrences, or a combination of them, could adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy. In addition, any physical damage to Enable's assets resulting from acts of terrorism may not be fully covered by Enable's insurance.

If Enable fails to maintain an effective system of internal controls, then it may not be able to accurately report financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in its financial reporting, which would harm Enable's business and the trading price of its common units.

Effective internal controls are necessary for Enable to provide reliable financial reports, prevent fraud and operate successfully as a public company. If its efforts to maintain an effective system of internal controls are not successful, it is unable to maintain adequate controls over its financial processes and reporting in the future or it is unable to comply with its obligations under Section 404 of the Sarbanes-Oxley Act of 2002, its operating results could be harmed or fail to meet its reporting obligations. Ineffective internal controls also could cause investors to lose confidence in its reported financial information, which would likely have a negative effect on the trading price of Enable's common units.

Enable depends on a small number of customers for a significant portion of its gathering and processing revenues and its transportation and storage revenues. The loss of, or reduction in volumes from, these customers could result in a decline in sales of its gathering and processing or transportation and storage services and adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

For the year ended December 31, 2020, 61 percent of Enable's natural gas gathered volumes were attributable to the affiliates of Continental Resources, Inc., Vine Oil and Gas, GeoSouthern Energy Corporation, XTO Energy Inc. and Marathon Oil Corporation and 46 percent of its transportation and storage service revenues were attributable to affiliates of CenterPoint, Spire Inc., Continental Resources, Inc., American Electric Power Co. and OGE Energy. The loss of any portion of the gathering, processing, transportation and storage systems serving any of these customers, the failure to extend existing contracts at their expiration or the extension or replacement of these contracts on less favorable terms could adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

Enable's exposure to credit risks of its customers, and any material nonpayment or nonperformance by its customers could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

Some of Enable's customers may experience financial problems that could have a significant effect on its customers' creditworthiness. Severe financial problems encountered by its customers could limit Enable's ability to collect amounts owed to it, or to enforce performance of obligations under contractual arrangements. In addition, many of Enable's customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of its customers' liquidity and limit its customers' ability to make payments or perform on obligations to Enable. For example, some of Enable's customers have experienced significantly reduced liquidity as a result of the economic effects caused by the COVID-19 pandemic. Furthermore, some of Enable's customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to Enable. Financial problems experienced by its customers could result in the impairment of its assets, reduction of its operating cash flows and may also reduce or curtail its customers' future use of its products and services, which could reduce revenues.

Enable and its operating subsidiaries' debt levels may limit their flexibility in obtaining additional financing and in pursuing other business opportunities.

As of December 31, 2020, Enable had approximately $4.0 billion of long-term debt outstanding, excluding the premiums, discounts and unamortized debt expense on senior notes. In addition, as of December 31, 2020, Enable had $250 million outstanding under its commercial paper program. Enable also has a $1.75 billion revolving credit facility for working capital, capital expenditures and other partnership purposes, including acquisitions, with no borrowings outstanding, of which approximately $1.50 billion in borrowing capacity was undrawn as of December 31, 2020. As of January 29, 2021, Enable had $204 million outstanding under its commercial paper program and $1.54 billion of undrawn borrowing capacity under its


26

revolving credit facility. Enable has the ability to incur additional debt, subject to limitations in its credit facilities. The levels of debt could have important consequences, including the following:

•the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all;
•a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;
•the debt level will make Enable more vulnerable to competitive pressures or a downturn in the business or the economy generally; and
•the debt level may limit flexibility in responding to changing business and economic conditions.

Enable's and its operating subsidiaries' ability to service their debt will depend upon, among other things, their future financial and operating performance, which will be affected by prevailing economic conditions, commodity prices and financial, business, regulatory and other factors, some of which are beyond their control. If operating results are not sufficient to service Enable's and its operating subsidiaries' current or future indebtedness, Enable and its subsidiaries may be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. These actions may not be effected on satisfactory terms, or at all.

Enable's credit facilities contain operating and financial restrictions, including covenants and restrictions that may be affected by events beyond its control, which could adversely affect its financial condition, results of operations and ability to make cash distributions to its unitholders, including OGE Energy.

Enable's credit facilities contain customary covenants that, among other things, limit the ability to:

•permit its subsidiaries to incur or guarantee additional debt;
•incur or permit to exist certain liens on assets;
•dispose of assets;
•merge or consolidate with another company or engage in a change of control;
•enter into transactions with affiliates on non-arm's length terms; and
•change the nature of its business.

Enable's credit facilities also require it to maintain certain financial ratios. Its ability to meet those financial ratios can be affected by events beyond its control, Enable cannot assure it will meet those ratios. In addition, its credit facilities contain events of default customary for agreements of this nature.

Enable's ability to comply with the covenants and restrictions contained in its credit facilities may be affected by events beyond its control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, its ability to comply with these covenants may be impaired. If any of the restrictions, covenants, ratios or tests in its credit facilities are violated, a significant portion of its indebtedness may become immediately due and payable. In addition, its lenders' commitments to make further loans to Enable under the revolving credit facility may be suspended or terminated. Enable might not have, or be able to obtain, sufficient funds to make these accelerated payments.

Any reductions in Enable's credit ratings could increase its financing costs and the cost of maintaining certain contractual relationships.

Enable cannot provide assurance that its credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant. If any of Enable's credit ratings are below investment grade, it may have higher future borrowing costs and it or its subsidiaries may be required to post cash collateral or letters of credit under certain contractual agreements. If cash collateral requirements were to occur at a time when Enable was experiencing significant working capital requirements or otherwise lacked liquidity, its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy, could be adversely affected.



27

Enable may not be able to recover the costs of its substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than it anticipates.

Enable's business plan calls for investment in capital improvements and additions. The construction of additions or modifications to Enable's existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties, many of which are beyond its control and may require the expenditure of significant amounts of capital, which may exceed estimates. These projects may not be completed at the planned cost, on schedule or at all. The construction of new pipeline, gathering, treating, processing, compression or other facilities is subject to construction cost overruns due to labor costs, costs and availability of equipment and materials such as steel, labor shortages or weather or other delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner, if at all, or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. Moreover, revenues and cash flows may not increase immediately upon the expenditure of funds on a particular project. For instance, if Enable expands an existing pipeline or a constructs a new pipeline, the construction may occur over an extended period of time, and Enable may not receive any material increases in revenues or cash flows until the project is completed. In addition, Enable may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, the new facilities may not be able to achieve an expected investment return, which could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including OGE Energy.

In connection with its capital investments, Enable may estimate, or engage a third party to estimate, potential reserves in areas to be developed prior to constructing facilities in those areas. To the extent Enable relies on estimates of future production in deciding to construct additions to its systems, those estimates may prove to be inaccurate either in volume or timing due to numerous uncertainties inherent in estimating future production. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to construction. Those rights-of-way to connect new natural gas supplies to existing gathering lines may be unavailable, and it may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy, could be adversely affected.

Enable's ability to grow is dependent in part on its ability to access external financing sources on acceptable terms.

Enable expects its operating subsidiaries will distribute all of their available cash to Enable and that it will distribute all of its available cash to its unitholders. As a result, Enable and its operating subsidiaries rely significantly upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. To the extent Enable or its operating subsidiaries are unable to finance growth externally or through internally generated cash flows, Enable's and its operating subsidiaries' cash distribution policy may significantly impair Enable's and its operating subsidiaries' ability to grow. In addition, because Enable and its operating subsidiaries distribute all available cash, Enable's and its operating subsidiaries' growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.

To the extent Enable issues additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that it will be unable to maintain or increase its per unit distribution level, which in turn may impact the available cash that Enable has to distribute on each unit. There are no limitations in the partnership agreement on its ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt by Enable or its operating subsidiaries to finance its growth strategy would result in increased interest expense, which in turn may negatively impact the available cash that its operating subsidiaries have to distribute to it, and thus that it has to distribute to its unitholders, including OGE Energy.

Enable depends in part on access to the capital markets and other external financing sources to fund its expansion capital expenditures, although Enable has also increasingly relied on cash flow generated from its operations to fund its expansion capital expenditures. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because Enable's common units are yield-based securities, rising market interest rates could impact the relative attractiveness of its common units to investors. As a result of capital market volatility, Enable may be unable to issue equity or debt on satisfactory terms, or at all, which may limit its ability to expand its operations or make future acquisitions.



28

Enable's merger and acquisition activities may not be successful or may result in completed acquisitions that do not perform as anticipated, which could adversely affect its financial position, results of operations or future growth.

From time to time, Enable has made, and it intends to continue to make, acquisitions of businesses and assets. Such acquisitions involve substantial risks, including the following:

•acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;
•acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;
•it may assume liabilities that were not disclosed to it, that exceed its estimates, or for which its rights to indemnification from the seller are limited;
•it may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and
•acquisitions, or the pursuit of acquisitions, could disrupt its ongoing businesses, distract management, divert resources and make it difficult to maintain its current business standards, controls and procedures.

In addition, Enable's growth strategy includes, in part, the ability to make acquisitions on economically acceptable terms. If Enable is unable to make acquisitions or if its acquisitions do not perform as anticipated, Enable's future growth may be adversely affected.

Enable may be unable to obtain or renew permits necessary for its operations, which could inhibit its ability to do business.

Performance of its operations require it obtain and maintain a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of Enable's compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay the issuance of a new or existing material permit or other approval, or to revoke or substantially modify an existing permit or other approval, could adversely affect its ability to initiate or continue operations at the affected location or facility and on its financial condition, results of operations and ability to make cash distributions to unitholders, including OGE Energy. For example, in April 2020, the federal district court for the District of Montana issued an order vacating the Corps Clean Water Act Section 4040 Nationwide Permit 12, which authorizes pipeline crossings of streams and wetlands. Subsequent proceedings limited this order to the Keystone XL pipeline, which is not related to Enable's operations. Pending appeal of the court's decision, the U.S. Army Corps of Engineers has published a proposal to reissue its existing Nationwide Permits and associated general conditions and definitions, with certain modifications, including to the Corps Clean Water Act Section 4040 Nationwide Permit 12. While the full extent and impact of the court's action, as well as the proposed Corps Clean Water Act Section 4040 Nationwide Permit 12 re-issuance, is unclear at this time, a disruption in Enable's ability to obtain coverage under the Corps Clean Water Act Section 4040 Nationwide Permit 12 or other general permits may result in increased costs and project delays if Enable is required to seek individual permits from the U.S. Army Corps of Engineers.

Additionally, in order to obtain permits and renewals of permits and other approvals in the future, Enable may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate, including on public and American Indian tribal lands. Certain approval procedures may require preparation of archaeological surveys, wetland delineations, endangered species surveys and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements may be expensive and may significantly lengthen the time required to prepare applications and to receive authorizations and consequently could disrupt Enable's project construction schedules.

Enable's operations may be impacted by certain indigenous rights protections.

Parts of Enable's operations cross land that has historically been apportioned to various Native American tribes, who may exercise significant jurisdiction and sovereignty over their lands. Enable's operations may be impacted to the extent these tribal governments are found to have and choose to act upon such jurisdiction over lands where it operates. For example, a U.S. Supreme Court ruling in 2020 found that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished, and subsequent court rulings applying this precedent have found similarly for other reservations. This ruling could lead to some confusion as to which agencies have authority to regulate activities in this area of Oklahoma.


29


Costs of compliance with existing environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

Enable is subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, delay or increase costs of construction, restrict or limit the output of certain facilities and/or require additional pollution control equipment and otherwise increase costs. For instance, in May 2016, the EPA issued final standards governing methane emissions imposing more stringent controls on methane and volatile organic compounds emissions at new and modified oil and natural gas production, processing, storage and transmission facilities. These rules have required changes to Enable's operations, including the installation of new equipment to control emissions. In September 2020, the EPA finalized amendments to the 2016 standards that removed Enable's transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, several lawsuits have been filed challenging these amendments, and on January 20, 2021, President Biden signed an executive order calling for the suspension, revision or recission of the September 2020 rule and the reinstatement or issuance of standards for new, modified and existing oil and gas operations, including Enable's transmission and storage segments. As a result, Enable cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, several states are pursuing similar measures to regulate emissions of methane from new and existing sources. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations. Future federal and state regulations relating to Enable's gathering and processing, transmission and storage operations remain a possibility and could result in increased compliance costs on Enable's operations. Furthermore, if new or more stringent federal, state or local legal restrictions are adopted in areas where Enable's crude oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which could adversely affect demand for Enable's services to those customers.

There is inherent risk of the incurrence of environmental costs and liabilities in Enable's operations due to the handling of natural gas, NGLs, crude oil and produced water as well as air emissions related to its operations and historical industry operations and waste disposal practices. These matters are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment and the protection of plants, wildlife, and natural and cultural resources. These laws and regulations can restrict or impact business activities in many ways, such as restricting the handling or disposing of wastes or requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of wastes on, under or from its properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under its control. Private parties, including the owners of the properties through which its gathering and transportation systems pass and facilities where its wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non- compliance, with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of its pipelines could subject them to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Enable may be unable to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary. Further, stricter requirements could negatively impact its customers' production and operations, resulting in less demand for its services.

Increased regulation of hydraulic fracturing and wastewater injection wells could result in reductions or delays in natural gas and crude oil production by Enable's customers, which could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

Hydraulic fracturing is a common practice that is used by many of Enable's customers to stimulate production of natural gas and crude oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions. In addition, certain federal agencies have proposed additional laws and regulations to more closely regulate the hydraulic fracturing process. The EPA has also issued regulations and guidance for hydraulic fracturing operations under several statutes.



30

Some states have adopted, and other states have considered adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, in some cases banning hydraulic fracturing entirely. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where Enable's oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which activities could adversely affect demand for Enable's services to those customers.

State and federal regulatory agencies have also focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. Some state regulatory agencies have adopted their regulations or issued orders to address induced seismicity. For example, the OCC has implemented volume reduction plans, and at times required shut-ins, for disposal wells injecting wastewater from oil and gas operations into the Arbuckle formation. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. Enable cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal. Additional legislation or regulation could also lead to operational delays or increased operating costs for Enable's customers, which in turn could reduce the demand for Enable's services.

Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing or other regulatory mechanisms.

Enable and its customers' operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, adversely impact Enable's results of operations and ability to make cash distributions to unitholders, including OGE Energy, limit the areas in which oil and natural gas production may occur and reduce demand for the products and services Enable provides.

The threat of possible global climate change continues to attract considerable attention in the U.S. and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of greenhouse gases as well as to restrict or eliminate such future emissions. As a result, Enable's operations as well as the operations of its crude oil and natural gas exploration and production customers are subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of greenhouse gases.

In the U.S., no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that greenhouse gas emissions constitute a pollutant under the Clean Air Act, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for greenhouse gas emissions from certain large stationary sources, require the monitoring and annual reporting of greenhouse gas emissions from certain petroleum and natural gas system sources in the U.S., and together with the Department of Transportation, implement greenhouse gas emissions limits on vehicles manufactured for operation in the U.S. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. For more information, see the risk factor, "Costs of compliance with existing environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy," above. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs and restriction of emissions. Internationally, the United Nations sponsored Paris Agreement requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. The U.S. had officially withdrawn from the "Paris Agreement" on November 4, 2020. However, newly elected President Biden announced on January 20, 2021 that the U.S. would rejoin the agreement and called on the federal government to begin formulating the U.S.'s nationally determined emissions reduction targets under the agreement.

Governmental, scientific and public concern over the threat of climate change arising from greenhouse gas emissions has resulted in increasing political risks in the U.S., including climate change related pledges, made by certain candidates recently elected to public office. These have included promises to limit emissions and curtail the production of oil and gas, such


31

as through the cessation of leasing public land for hydrocarbon development. For example, on January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry and increased emphasis on climate-related risk across governmental agencies and economic sectors. Separately, on January 20, 2021, the Acting Secretary of the U.S. Department of the Interior issued an order that, among other things, imposed a temporary suspension on the issuance of fossil fuel authorizations, including leases and permits, on federal lands. Although the order says it does not limit existing operations under valid leases, on January 27, 2021, President Biden signed an executive order suspending new oil and gas leasing on federal lands, pending completion of a review of the federal government's oil and gas permitting and leasing practices. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquefied natural gas export facilities. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change. Suits have also been brought against such companies under shareholder and consumer production laws, alleging that the companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into other related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has applied to join the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. A material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation and processing activities, which could result in decreased demand for Enable's services.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for greenhouse gas emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate greenhouse gas emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for Enable's services and products. Additionally, political, litigation and financial risks may result in Enable's oil and natural gas customers restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes or impairing their ability to continue to operate in an economic manner, which also could reduce demand for Enable's services and products. One or more of these developments could have a material adverse effect on Enable's business, financial condition, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

Finally, many scientists have concluded that increasing concentrations of greenhouse gases in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect Enable's results of operations and ability to make cash distributions to unitholders, including OGE Energy. In addition, while Enable's consideration of changing weather conditions and inclusion of safety factors in design covers the uncertainties that climate change and other events may potentially introduce, its ability to mitigate the adverse impacts of these events depends in part on the effectiveness of its facilities and disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.

Enable's operations are subject to extensive regulation by federal regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including OGE Energy.

The rates charged by several of Enable's pipeline systems, including for interstate gas transportation service provided by its intrastate pipelines, are regulated by the FERC. The FERC and state regulatory agencies also regulate other terms and conditions of the services it may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower its tariff rates or deny any rate increase or other material changes to the types or terms and conditions of service it might propose or offer, the profitability of its pipeline businesses could suffer. If it were permitted to raise its tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which could also limit profitability. Furthermore, competition from other transportation and storage systems may prevent them from raising its tariff rates even if permitted by regulatory agencies. The regulatory agencies that regulate its systems periodically implement new rules, regulations and terms and conditions of services


32

subject to its jurisdiction. New initiatives or orders may adversely affect the rates charged for services or otherwise adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including OGE Energy.

Enable's natural gas interstate pipelines are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. Generally, the FERC's authority over interstate natural gas transportation extends to:

•rates, operating terms, conditions of service and service contracts;
•certification and construction of new facilities;
•extension or abandonment of services and facilities or expansion of existing facilities;
•maintenance of accounts and records;
•acquisition and disposition of facilities;
•initiation and discontinuation of services;
•depreciation and amortization policies;
•conduct and relationship with certain affiliates;
•market manipulation in connection with interstate sales, purchases or natural gas transportation; and
•various other matters.

Should Enable fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 to impose penalties for current violations of up to approximately $1.3 million per day for each violation as well as possible criminal penalties.

The FERC's jurisdiction extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to expansions, lateral and other facilities and abandonment of facilities and services. Prior to commencing construction of significant new interstate transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or an order amending its existing certificate, from the FERC. Certain minor expansions are authorized by blanket certificates that the FERC has issued by rule. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any failure by an agency to issue sufficient authorizations or permits in a timely manner for one or more of these projects may mean that Enable will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that Enable did not anticipate. Enable's inability to obtain sufficient permits and authorizations in a timely manner could materially and negatively impact the additional revenues expected from these projects.

The FERC conducts audits to verify compliance with the FERC's regulations and the terms of its orders, including whether the websites of interstate pipelines accurately provide information on the operations and availability of services. The FERC's regulations require uniform terms and conditions for service, as set forth in agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the standard form of service agreements set forth in the pipeline's FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that the FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement or require Enable to seek modification, or alternatively require Enable to modify its tariff so that the non-conforming provisions are generally available to all customers.

The rates, terms and conditions for transporting natural gas in interstate commerce on certain of Enable's intrastate pipelines and for services offered at certain of Enable's storage facilities are subject to the jurisdiction of the FERC under Section 311 of the Natural Gas Policy Act of 1978. Rates to provide such interstate transportation service must be "fair and equitable" under the Natural Gas Policy Act of 1978 and are subject to review, refund with interest if found not to be fair and equitable, and approval by the FERC at least once every five years.

Enable's crude oil gathering systems in the Williston Basin are subject to common carrier regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that Enable maintain tariffs on file with the FERC setting forth the rates Enable charges for providing transportation services, as well as the rules and regulations governing such services. The Interstate Commerce Act also requires, among other things, that Enable's rates must be "just and reasonable" and that Enable provide service in a manner that is nondiscriminatory. Shippers on Enable's FERC-regulated crude oil gathering systems may protest its tariff filings, file complaints against its existing rates, or the FERC can investigate Enable's rates on its own initiative. If FERC finds that Enable's existing or proposed rates are unjust and unreasonable, it could deny requested rate increases or could order Enable to reduce its rates and could require the payment of reparations to complaining shippers for up to two years prior to the complaint.


33


Enable's operations may also be subject to regulation by state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including OGE Energy.

The pipeline operations of Enable that are not regulated by the FERC may be subject to state and local regulation applicable to intrastate natural gas and transportation services. State and local regulations generally focus on safety, environmental and, in some circumstances, prohibition of undue discrimination among shippers. Additional rules and legislation pertaining to these matters are considered and, in some instances, adopted from time to time. Enable cannot predict what effect, if any, such changes might have on operations, but it could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect the business. Any such state or local regulation could have an adverse effect on the business and the financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

A change in the jurisdictional characterization of some of Enable's assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.

Enable's natural gas gathering and intrastate transportation systems are generally exempt from the jurisdiction of the FERC under the Natural Gas Act of 1938, and its crude oil gathering system in the Anadarko Basin is generally exempt from the jurisdiction of FERC under the Interstate Commerce Act. Nevertheless, FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. The FERC's policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, it cannot be assured that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the intrastate natural gas transportation business. Although the FERC has not made a formal determination with respect to all of Enable's facilities it considers to be engaged in natural gas gathering or a formal determination with respect to its facilities that it considers to be engaged in intrastate crude oil gathering, Enable believes that its natural gas gathering facilities meet the traditional tests that the FERC has used to determine that a pipeline is a natural gas gathering pipeline and Enable's intrastate crude oil gathering facilities meet the traditional tests that the FERC has used to determine that a pipeline is not engaged in interstate crude oil transportation. The distinction between FERC-regulated facilities, however, has been the subject of substantial litigation, and the FERC determines whether facilities are subject to regulation under the Natural Gas Act of 1938 or the Interstate Commerce Act on a case-by-case basis, so the classification and regulation of its facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenue, increase operating costs and, depending upon the facility in question, could adversely affect Enable's financial condition, results of operations and ability to make cash distributions to its unitholders, including OGE Energy. In addition, if any of Enable's facilities were found to have provided services or otherwise operated in violation of the Natural Gas Act of 1938, Natural Gas Policy Act of 1978 or Interstate Commerce Act regulations, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by the FERC.

Natural gas gathering and intrastate crude oil gathering may receive greater regulatory scrutiny at the state level; therefore, these operations could be adversely affected should it become subject to the application of state regulation of rates and services. Enable's gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. Enable cannot predict what effect, if any, such changes might have on its operations, but it could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Enable may incur significant costs and liabilities resulting from compliance with pipeline safety laws and regulations, pipeline integrity and other similar programs and related repairs.

Certain of Enable's pipeline operations are subject to pipeline safety laws and regulations. The U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration regulates safety requirements for the design, construction, maintenance and operation of its jurisdictional natural gas and hazardous liquids pipeline facilities. All of Enable's interstate and intrastate natural gas transportation pipeline facilities are Pipeline and Hazardous Materials Safety Administration jurisdictional and certain of Enable's natural gas gathering, NGLs and crude oil pipeline facilities are Pipeline and Hazardous


34

Materials Safety Administration jurisdictional. Among other things, these laws and regulations require pipeline operators to develop integrity management programs, including more frequent inspections and other measures, for pipelines located in "high consequence areas." The regulations require operators, including Enable, to, among other things:

•perform ongoing assessments of pipeline integrity;
•develop a baseline plan to prioritize the assessment of a covered pipeline segment;
•identify and characterize applicable threats that could impact a high consequence area;
•improve data collection, integration, and analysis;
•repair and remediate pipelines as necessary; and
•implement preventive and mitigating action.

Failure to comply with the Pipeline and Hazardous Materials Safety Administration or comparable state pipeline safety regulations could result in a number of consequences which may have an adverse effect on Enable's operations. Enable incurs significant costs associated with its compliance with existing Pipeline and Hazardous Materials Safety Administration and comparable state pipeline regulations. Enable incurred maintenance capital expenditures and operation and maintenance expenses of $66 million in 2020 and currently estimates that it will incur maintenance capital expenditures and operation and maintenance expenses of up to $68 million in 2021 under its pipeline safety program, including costs related to integrity assessments and repairs, threat and risk analyses, implementing preventative and mitigative measures, and conducting activities to support the maximum allowable operating pressure for gas pipelines or the maximum operating pressure for hazardous liquid pipelines. Enable may incur significant cost associated with repair, remediation, preventive and mitigation measures associated with its integrity management programs for pipelines that are not currently subject to regulation by the Pipeline and Hazardous Materials Safety Administration.

Changes to existing pipeline safety regulations may result in increased operating and compliance costs. For example, in October 2019, the Pipeline and Hazardous Materials Safety Administration published three final rules on pipeline safety that create or expand reporting, inspection, maintenance and other pipeline safety obligations. While Enable has estimated the impact of these rules on its future costs of operations, actual costs to comply may be significantly higher.

The Pipeline and Hazardous Materials Safety Administration is working on two additional rules related to gas pipeline safety, though Enable cannot predict when they will be finalized. The rule entitled "Pipeline Safety: Safety of Gas Transmission Pipelines, Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments" is expected to adjust the repair criteria for pipelines in high consequence areas, create new criteria for pipelines in non-high consequence areas, and strengthen integrity management assessment requirements. The rule entitled "Safety of Gas Gathering Pipelines" is expected to require all gas gathering pipeline operators to report incidents and annual pipeline data and to extend regulatory safety requirements to certain gas gathering pipelines in rural areas. The adoption of these or other regulations requiring more comprehensive or stringent safety standards could require Enable to install new or modified safety controls, pursue new capital projects or conduct maintenance programs on an accelerated basis, all of which could require Enable to incur increased and potentially significant operational costs.

Financial reform regulations under the Dodd-Frank Act could adversely affect Enable's ability to use derivative instruments to hedge risks associated with its business.

At times, Enable may hedge all or a portion of its commodity risk and its interest rate risk. The federal government regulates the derivatives markets and entities, including businesses like Enable, that participate in those markets through the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which requires the Commodity Futures Trading Commission and the Securities and Exchange Commission to promulgate rules and regulations implementing the legislation. Under the Commodity Futures Trading Commission's regulations, Enable is subject to reporting and recordkeeping obligations for transactions involving non-financial swap transactions. The Commodity Futures Trading Commissions initially adopted regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, but these rules were successfully challenged in federal district court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. In December 2013, the Commodity Futures Trading Commission published a notice of proposed rulemaking designed to implement new position limits regulation and in December 2016, the Commodity Futures Trading Commission's re-proposal position limits regulations. The ultimate form and timing of the implementation of the regulatory regime affecting commodity derivatives remains uncertain.

The Commodity Futures Trading Commission has imposed mandatory clearing requirements on certain categories of swaps, including certain interest rate swaps, but has exempted derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement, where a counterparty such as Enable has a required identification number, is not a


35

financial entity as defined by the regulations, and meets a minimum asset test. Enable's management believes its hedging transactions qualify for this "commercial end-user" exception. The Dodd-Frank Act may also require Enable to comply with margin requirements in connection with its hedging activities, although the application of those provisions to Enable is uncertain at this time. The Dodd-Frank Act may also require the counterparties to its derivative instruments to spin off some of their hedging activities to a separate entity, which may not be as creditworthy as the current counterparty.

The Dodd-Frank Act and related regulations could significantly increase the cost of derivatives contracts for Enable's industry (including requirements to post collateral which could adversely affect Enable's available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks Enable encounters, reduce its ability to monetize or restructure its existing derivatives contracts, and increase its exposure to less creditworthy counterparties, particularly if Enable is unable to utilize the commercial end user exception with respect to certain of its hedging transactions. If Enable reduces its use of hedging as a result of the legislation and regulations, its results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect its ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Enable's revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could adversely affect its financial position, results of operations and its ability to make cash distributions to unitholders, including OGE Energy.

Enable derives a substantial portion of its gross margin from subsidiaries through which it holds a substantial portion of its assets.

Enable derives a substantial portion of its gross margin from, and holds a substantial portion of its assets through, its subsidiaries. As a result, it depends on distributions from its subsidiaries in order to meet its payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide Enable with funds for its payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit its subsidiaries' ability to make payments or other distributions, and its subsidiaries could agree to contractual restrictions on its ability to make distributions.

The right by Enable to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary's creditors, including trade creditors. In addition, even if Enable were a creditor of any subsidiary, its rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by them.

Enable conducts a portion of its operations through joint ventures, which subjects them to additional risks that could adversely affect the success of these operations and Enable's financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy.

Enable conducts a portion of its operations through joint ventures with third parties, including Enbridge Inc., DCP Midstream Partners, LP, CVR Energy, Inc., Trans Louisiana Gas Pipeline, Inc. and Pablo Gathering, LLC. It may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture. The performance of these third-party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside the control of Enable. If these parties do not satisfy their obligations under these arrangements, Enable's business may be adversely affected.

The joint venture arrangements of Enable may involve risks not otherwise present when operating assets directly, including, for example:

•joint venture partners may share certain approval rights over major decisions;
•joint venture partners may not pay their share of the obligations, leaving Enable liable for their shares of joint venture liabilities;
•possible inability to control the amount of cash it will receive from the joint venture;
•it may incur liabilities as a result of an action taken by its joint venture partners;
•it may be required to devote significant management time to the requirements of and matters relating to the joint ventures;
•its insurance policies may not fully cover loss or damage incurred by both them and its joint venture partners in certain circumstances;


36

•its joint venture partners may be in a position to take actions contrary to its instructions or requests or contrary to its policies or objectives; and
•disputes between them and its joint venture partners may result in delays, litigation or operational impasses.

The risks described above or the failure to continue joint ventures or to resolve disagreements with joint venture partners could adversely affect Enable's ability to transact the business that is the subject of such joint venture, which would in turn adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including OGE Energy. The agreements under which certain joint ventures were formed may subject them to various risks, limit the actions it may take with respect to the assets subject to the joint venture and require Enable to grant rights to its joint venture partners that could limit its ability to benefit fully from future positive developments. Some joint ventures require Enable to make significant capital expenditures. If it does not timely meet its financial commitments or otherwise do not comply with its joint venture agreements, its rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely affected. Certain of its joint venture partners may have substantially greater financial resources than Enable has and it may not be able to secure the funding necessary to participate in operations its joint venture partners propose, thereby reducing its ability to benefit from the joint venture.

Under certain circumstances, Enbridge Inc. could have the right to purchase an ownership interest in SESH at fair market value.

Enable owns a 50 percent ownership interest in SESH. The remaining 50 percent ownership interests are held by Enbridge Inc. As of December 31, 2020, CenterPoint owns 53.7 percent of Enable's common units, 100.0 percent of its Series A Preferred Units and a 40 percent economic interest in Enable GP, LLC. Pursuant to the terms of the limited liability company agreement of SESH, as amended, if, at any time, CenterPoint has a right to receive less than 50 percent of Enable's distributions through its interests in Enable and in the general partner, or does not have the ability to exercise certain control rights, Enbridge Inc. could have the right to purchase Enable's interest in SESH at fair market value, subject to certain exceptions.

The amount of cash Enable has available for distribution to its limited partners depends primarily on its cash flow rather than on its profitability, which may prevent Enable from making distributions, even during periods in which it records net income.

The amount of cash Enable has available for distribution depends primarily upon its cash flow rather than on profitability. Profitability is affected by non-cash items but cash flow is not. As a result, Enable may make cash distributions during periods when it records losses for financial accounting purposes and may not make cash distributions during periods when it records net earnings for financial accounting purposes.

Affiliates of Enable's general partner, including CenterPoint and OGE Energy, may compete with Enable, and neither the general partner nor its affiliates have any obligation to present business opportunities to Enable.

Under Enable's omnibus agreement, both CenterPoint and OGE Energy are prohibited from, directly or indirectly, owning, operating, acquiring or investing in any business engaged in midstream operations located within the U.S., other than through Enable. This requirement applies to both CenterPoint and OGE Energy for so long as either CenterPoint or OGE Energy holds any interest in Enable's general partner or at least 20 percent of its common units. However, if CenterPoint or OGE Energy acquires any business with midstream operations assets that have a value in excess of $50.0 million (or $100.0 million in the aggregate with such party's other acquired midstream operations assets that have not been offered to Enable), the acquiring party will be required to offer to Enable such assets for such value. If Enable does not purchase such assets, the acquiring party will be free to retain and operate such midstream assets, so long as the value of the assets does not reach certain thresholds.

As a result, under the circumstances described above, CenterPoint and OGE Energy have the ability to construct or acquire assets that directly compete with Enable's assets. Pursuant to the terms of Enable's partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to Enable's general partner or any of its affiliates, including its executive officers and directors and CenterPoint and OGE Energy. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for Enable will not have any duty to communicate or offer such opportunity to Enable. Any such person or entity will not be liable to Enable or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to Enable. This may create actual and potential conflicts of interest between Enable and affiliates of its general partner and result in less than favorable treatment of Enable and its common unitholders.



37

Enable may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.

Enable's partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that it may issue at any time without the approval of its unitholders. The issuance by Enable of additional common units or other equity securities of equal or senior rank will have the following effects:

•Enable's existing unitholders' proportionate ownership interest in Enable will decrease;
•the amount of distributable cash flow on each unit may decrease;
•because the amount payable to holders of incentive distribution rights is based on a percentage of the total distributable cash flow, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;
•the ratio of taxable income to distributions may increase;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of the common units may decline.

In addition, upon a change of control or certain fundamental transactions, Enable's Series A Preferred Units are convertible into common units at the option of the holders of such units. If a substantial portion of the Series A Preferred Units were converted into common units, common unitholders could experience significant dilution. In addition, if holders of such converted Series A Preferred Units were to dispose of a substantial portion of these common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price for Enable's common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for Enable to sell its common units in the future.

Affiliates of Enable's general partner may sell common units in the public or private markets, which could have an adverse impact on the trading price of the common units and may sell their interest in its general partner, which may impact its strategic direction.

As of January 29, 2021, CenterPoint held 233,856,623 of Enable's common units and 14,520,000 Series A Preferred Units, and OGE Energy held 110,982,805 of Enable's common units. Enable's Series A Preferred Units are convertible into common units upon a change of control or certain fundamental transactions at the option of the holders of such units. Both Enable's common units held by CenterPoint and OGE Energy, as well as Enable's Series A Preferred Units held by CenterPoint, are subject to certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop. In addition, any sale of Enable's general partner by CenterPoint or OGE Energy may impact Enable's strategic direction, business or results of operations.

Enable's Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of its common units.

Enable's Series A Preferred Units rank senior to all of its other classes or series of equity securities with respect to distribution rights and rights upon liquidation. Enable cannot declare or pay a distribution to its common unitholders for any quarter unless full distributions have been or contemporaneously are being paid on all outstanding Series A Preferred Units for such quarter. These preferences could adversely affect the market price for Enable's common units or could make it more difficult for Enable to sell its common units in the future.

Holders of the Series A Preferred Units will receive, on a non-cumulative basis and if and when declared by Enable's general partner, a quarterly cash distribution, subject to certain adjustments, equal to an annual rate of 10 percent on the stated liquidation preference from the date of original issue to, but not including, the five year anniversary of the original issue date, and an annual rate of the London interbank offered rate, or LIBOR, plus a spread of 850 basis points on the stated liquidation preference thereafter. In connection with certain transfers of the Series A Preferred Units, the Series A Preferred Units will automatically convert into one or more new series of preferred units (the "other preferred units") on the later of the date of transfer or the second anniversary of the date of issue. The other preferred units will have the same terms as Enable's Series A Preferred Units except that unpaid distributions on the other preferred units will accrue from the date of their issuance on a cumulative basis until paid. Enable's Series A Preferred Units are convertible into common units by the holders of such units in certain circumstances. Payment of distributions on Enable's Series A Preferred Units, or on the common units issued following the conversion of such Series A Preferred Units, could impact its liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. Enable's obligations to the holders of Series A Preferred Units could also limit its ability to obtain additional financing or increase its borrowing costs, which could have an adverse effect on its financial condition.



38

Enable's Series A Preferred Units contain covenants that may limit its business flexibility.

Enable's Series A Preferred Units contain covenants preventing it from taking certain actions without the approval of the holders of 66 2/3 percent of the Series A Preferred Units. The need to obtain the approval of holders of the Series A Preferred Units before taking these actions could impede Enable's ability to take certain actions that its management or its board of directors may consider to be in the best interests of its unitholders. The affirmative vote of 66 2/3 percent of the outstanding Series A Preferred Units, voting as a single class, is necessary to amend Enable's Partnership Agreement in any manner that would or could reasonably be expected to have a material adverse effect on the rights, preferences, obligations or privileges of the Series A Preferred Units. The affirmative vote of 66 2/3 percent of the outstanding Series A Preferred Units and any outstanding series of other preferred units, voting as a single class, is necessary to (A) create or issue certain party securities with proceeds in an aggregate amount in excess of $700.0 million or create or issue any senior securities or (B) subject to Enable's right to redeem the Series A Preferred Units, approve certain fundamental transactions.

Enable's Series A Preferred Units are required to be redeemed in certain circumstances if they are not eligible for trading on the New York Stock Exchange, and Enable may not have sufficient funds to redeem its Series A Preferred Units if it is required to do so.

The holders of Enable's Series A Preferred Units may request that Enable list those units for trading on the New York Stock Exchange. If Enable is unable to list the Series A Preferred Units in certain circumstances, it will be required to redeem the Series A Preferred Units. There can be no assurance that Enable would have sufficient financial resources available to satisfy its obligation to redeem the Series A Preferred Units. In addition, mandatory redemption of Enable's Series A Preferred Units could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including OGE Energy.

Enable's Pending Merger with Energy Transfer

Because the exchange ratio is fixed and because the market price of Energy Transfer’s common units may fluctuate, Enable's unitholders, including OGE Energy, cannot be certain of the precise value of any merger consideration they may receive in the Energy Transfer merger.

At the time the Energy Transfer merger is completed, each issued and outstanding common unit of Enable will be converted into the right to receive the merger consideration of 0.8595 of one common unit representing limited partner interests in Energy Transfer. The exchange ratio for the merger consideration is fixed, and there will be no adjustment to the merger consideration for changes in the market price of Energy Transfer common units or Enable's common units prior to the completion of the merger. If the merger is completed, there will be a time lapse between the date of signing the merger agreement and the date on which Enable's unitholders, including OGE Energy, who are entitled to receive the merger consideration actually receive the merger consideration. The market value of Energy Transfer's common units may fluctuate during this period as a result of a variety of factors, including general market and economic conditions, changes in Energy Transfer's businesses, operations and prospects and regulatory considerations. Such factors are difficult to predict and in many cases may be beyond Enable's and Energy Transfer's control. The actual value of any merger consideration received by Enable's unitholders, including OGE Energy, upon the completion of the merger will depend on the market value of the common units of Energy Transfer at that time. This market value may differ, possibly materially, from the market value of Energy Transfer's common units at the time the merger agreement was entered into or at any other time. Enable's unitholders, including OGE Energy, should obtain current quotations for Energy Transfer's common units and for Enable's common units.

The merger may not be completed and the merger agreement may be terminated in accordance with its terms.

The merger is subject to a number of conditions that must be satisfied or waived prior to the completion of the merger, including (i) the receipt of the required approvals from Enable's unitholders, including OGE Energy, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Act, (iii) the absence of any governmental order or law that prohibits or makes illegal the consummation of the merger, (iv) Energy Transfer common units issuable in connection with the merger having been authorized for listing on the New York Stock Exchange, subject to official notice of issuance and (v) Energy Transfer's registration statement on Form S-4 having been declared effective by the Securities and Exchange Commission under the Securities Act of 1933. The obligation of each party to consummate the merger is also conditioned upon the other party's representations and warranties being true and correct (subject to certain materiality exceptions) and the other party having performed in all material respects its obligations under the merger agreement. The obligation of Enable to consummate the merger is further conditioned upon the receipt of a customary tax opinion of counsel to Enable that for U.S. federal income tax purposes, subject to certain exceptions, (i) Enable should not recognize any income or gain as a result of the merger and (ii) no gain or loss should be recognized by holders of Enable's common units or Series A Preferred Units as a result


39

of the merger. These conditions to the completion of the merger may not be satisfied or waived in a timely manner or at all, and, accordingly, the merger may be delayed or may not be completed.

Moreover, if the merger is not completed by November 30, 2021, either Energy Transfer or Enable may choose not to proceed with the Energy Transfer merger, and the parties can mutually decide to terminate the merger agreement at any time, before or after approval by Enable's common unitholders, including OGE Energy. In addition, Energy Transfer and Enable may elect to terminate the merger agreement in certain other circumstances as further detailed in the merger agreement.

The merger agreement limits Enable's ability to pursue alternatives to the merger.

The merger agreement contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to Enable's unitholders, including OGE Energy, than the merger, or may result in a potential competing acquirer proposing to pay a lower per unit price to acquire Enable than it might otherwise have proposed to pay. These provisions include covenants not to solicit, initiate or knowingly encourage or facilitate proposals relating to alternative transactions or, subject to certain exceptions, enter into discussions concerning or provide any non-public information in connection with alternative transactions.

Failure to complete the merger could negatively impact the price of Enable's common units, as well as Enable's future businesses and financial results.

The merger agreement contains a number of conditions that must be satisfied or waived prior to the completion of the merger. There can be no assurance that all of the conditions to the completion of the merger will be so satisfied or waived. If these conditions are not satisfied or waived, Enable will be unable to complete the merger.

If the merger is not completed for any reason, including the failure to receive the required approval of holders of Enable's common units, including OGE Energy, Enable's future businesses and financial results may be adversely affected, including as follows:

•Enable may experience negative reactions from the financial markets, including negative impacts on the market price of Enable's common units;
•the manner in which customers, vendors, business partners and other third parties perceive Enable may be negatively impacted, which in turn could affect its marketing operations or its ability to compete for new business or obtain renewals in the marketplace more broadly;
•Enable will still be required to pay certain significant costs relating to the merger, such as legal, accounting, financial advisor and printing fees;
•Enable may experience negative reactions from employees; and
•Enable will have expended time and resources that could otherwise have been spent on its existing businesses and the pursuit of other opportunities that could have been beneficial to Enable.

In addition to the above risks, if the merger agreement is terminated and Enable's board of directors seeks an alternative transaction, Enable's unitholders, including OGE Energy, cannot be certain that Enable will be able to find a party willing to engage in a transaction on more attractive terms than the merger. If the merger agreement is terminated under specified circumstances, Enable may be required to pay Energy Transfer a termination fee.

Enable will be subject to business uncertainties while the merger is pending, which could adversely affect its businesses.

Uncertainties about the effect of the merger on employees and customers may have an adverse effect on Enable. These uncertainties may impair Enable's ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter and could cause customers and others that deal with Enable to seek to change their existing business relationships with Enable. Employee retention may be particularly challenging during the pendency of the merger, as employees may experience uncertainty about their roles with Energy Transfer following the merger. In addition, the merger agreement restricts Enable from entering into certain corporate transactions and taking other specified actions without the consent of Energy Transfer, and generally requires Enable to continue its operations in the ordinary course, until completion of the merger. These restrictions may prevent Enable from pursuing attractive business opportunities that may arise prior to the completion of the merger.



40

The common units representing limited partner interests in Energy Transfer to be received by Enable's common unitholders, including OGE Energy, upon completion of the merger will have different rights than Enable's common units.

Upon completion of the merger, Enable's unitholders, including OGE Energy, will no longer be unitholders of Enable. Instead, Enable's former unitholders, including OGE Energy, will become Energy Transfer unitholders and while their rights as Energy Transfer unitholders will continue to be governed by the laws of the state of Delaware, their rights will be subject to and governed by the terms of the Energy Transfer certificate of limited partnership, as amended, and the third amended and restated agreement of limited partnership of Energy Transfer, as amended. The laws of the state of Delaware and terms of the Energy Transfer certificate of limited partnership and the Energy Transfer third amended and restated agreement of limited partnership are in some respects different than the terms of Enable's certificate of limited partnership and Enable's partnership agreement, which currently govern the rights of Enable's unitholders, including OGE Energy.

Completion of the merger may trigger change in control or other provisions in certain agreements to which Enable is a party.

The completion of the merger may trigger change in control or other provisions in certain agreements to which Enable is a party. If Enable is unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements, or seeking monetary damages. Even if Enable is able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to Enable.

Enable will incur significant transaction and merger-related costs in connection with the merger, which may be in excess of those anticipated by Enable.

Enable has incurred and expects to continue to incur a number of non-recurring costs associated with negotiating and completing the merger, combining the operations of the two partnerships and achieving desired synergies. These fees and costs have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs related to the merger and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and benefit costs and filing fees. Many of these costs will be borne by Enable even if the merger is not completed.

Enable may be a target of securities class action and derivative lawsuits which could result in substantial costs and may delay or prevent the merger from being completed.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements. Even if the lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the merger, then that injunction may delay or prevent the merger from being completed, which may adversely affect Enable's business, financial position and results of operation. Currently, Enable is unaware of any securities class action lawsuits or derivative lawsuits having been filed in connection with the merger.

GENERAL RISKS

Governmental and market reactions to events involving other public companies or other energy companies that are beyond our control may have negative impacts on our business, financial position, results of operations, cash flows and access to capital.

Accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities and political contributions, could lead to public and regulatory scrutiny and suspicion for public companies, including those in the regulated and unregulated utility business. Accounting irregularities could cause regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. The capital markets and rating agencies also could increase their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect any of these types of events may have on our business, financial position, cash flows or access to the capital markets. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or


41

decreases in assets or increases in liabilities that could, in turn, affect our financial position, results of operations and cash flows.

Economic conditions could negatively impact our business and our results of operations.
 
Our operations are affected by local, national and worldwide economic conditions. The consequences of a recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital. Economic conditions may also impact the valuation of certain long-lived assets, including our investment in unconsolidated affiliates, that are subject to impairment testing, potentially resulting in impairment charges, which could have a material adverse impact on our results of operations. In March 2020, OGE Energy recognized an impairment charge related to its investment in Enable, which resulted from decreased demand for commodities as a result of COVID-19. The impairment charge had a material adverse impact on OGE Energy's results of operations for the year ended December 31, 2020.
 
Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which could impact the ability of our customers to pay timely, increase customer bankruptcies, and could lead to increased bad debt. If such circumstances occur, we expect that commercial and industrial customers would be impacted first, with residential customers following.
 
In addition, economic conditions, particularly budget shortfalls, could increase the pressure on federal, state and local governments to raise additional funds by increasing corporate tax rates and/or delaying, reducing or eliminating tax credits, grants or other incentives that could have a material adverse impact on our results of operations and cash flows.
 
We are subject to financial risks associated with climate change.

Climate change creates financial risk. Potential regulation associated with climate change legislation could pose financial risks to OGE Energy and its affiliates. On November 4, 2020, the U.S. officially withdrew from the United Nations' "Paris Agreement" on climate change. Newly elected President Biden announced on January 20, 2021 that the U.S would rejoin the agreement. The "Paris Agreement" or other legal requirements that result in enforceable greenhouse gas emission reduction requirements could lead to increased compliance costs for OGE Energy and its affiliates. In addition, to the extent that any climate change adversely affects the national or regional economic health through physical impacts or increased rates caused by the inclusion of additional regulatory costs, CO2 taxes or imposed costs, OGE Energy and its affiliates may be adversely impacted. There are also increasing risks for energy companies from shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change who may elect in the future to shift some or all of their investments into entities that emit lower levels of greenhouse gases or into non-energy related sectors. Institutional investors and lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable investing and lending practices and some of them may elect not to provide funding for fossil fuel energy companies. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

In addition, we may be subject to financial risks from private party litigation relating to greenhouse gas emissions. Defense costs associated with such litigation can be significant and an adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.

We are subject to cybersecurity risks and increased reliance on processes automated by technology.

In the regular course of our business, we handle a range of sensitive security and customer information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems such as theft or inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on our financial position, results of operations and cash flows.
OG&E operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, the technology systems are vulnerable to disability, failures or unauthorized access. Such failures or breaches of the systems could impact the reliability of OG&E's generation, transmission and distribution systems which may result in a loss of service to customers and also subject OG&E to financial harm due to the significant expense to respond to security breaches or repair system damage. OG&E's Smart


42

Grid program further increases potential risks associated with cybersecurity attacks. Our generation and transmission systems are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations could also negatively impact our business. If the technology systems were to fail or be breached and not recovered in a timely manner, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on our financial position, results of operations and cash flows.
Security threats continue to evolve and adapt. We and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to gain unauthorized access to systems, or confidential data, or to disrupt operations. None of these attempts has individually or in aggregate resulted in a security incident with a material impact on our financial condition or results of operations. Despite implementation of security and control measures, there can be no assurance that we will be able to prevent the unauthorized access of our systems and data, or the disruption of our operations, either of which could have a material impact. Our security procedures, which include among others, virus protection software, cybersecurity and our business continuity planning, including disaster recovery policies and back-up systems, may not be adequate or implemented properly to fully address the adverse effect of cybersecurity attacks on our systems, which could adversely impact our operations.
We maintain property, casualty and cybersecurity insurance that may cover certain resultant cyber and physical damage or third-party injuries caused by potential cyber events. However, damage and claims arising from such incidents may exceed the amount of any insurance available and other damage and claims arising from such incidents may not be covered at all. For these reasons, a significant cyber incident could reduce future net income and cash flows and impact financial condition.

Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities or sustained military campaigns may adversely impact our financial position, results of operations and cash flows.
 
The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the electric utility and natural gas midstream industry in general, and on us in particular, cannot be known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities or sustained military campaigns may affect our operations in unpredictable ways, including disruptions of supplies and markets for our products, and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than existing insurance coverage.
 

We face risks related to health epidemics and other outbreaks.

The outbreak of COVID-19 continues to be a developing situation around the globe that has adversely impacted economic activity and conditions worldwide. In particular, efforts to control the spread of COVID-19 have led to shutdowns of various facilities as well as disrupted supply chains around the world. Efforts to control the spread of COVID-19 have also resulted in remote work arrangements, increased unemployment, customer slow payment or non-payment and decreased commercial and industrial load in the U.S. generally and in our service territory to a lesser extent. We expect these particular COVID-19 impacts will likely continue in the near future. We are continuing to monitor developments involving our workforce, customers and suppliers and cannot predict whether COVID-19 will have a material impact on our results of operations, financial condition and prospects. However, an extended slowdown of the United States' economic growth, demand for commodities and/or material changes in governmental policy could result in lower economic growth and lower demand for electricity in our key markets as well as the ability of various customers, contractors, suppliers and other business partners to fulfill their obligations, which could have a material adverse effect on our results of operations, financial condition and prospects. Further, the negative impacts on the economy could also adversely impact the market value of the assets that fund our pension plans, which could necessitate accelerated funding of the plans to meet minimum federal government requirements.

The effects of COVID-19 and concerns regarding its continued global spread have negatively impacted domestic and international demand for natural gas, NGLs and crude oil, which has and could continue to contribute to price volatility and materially and adversely affect Enable's customers' operations and future production, resulting in less demand for Enable's services and/or the reduction of commercial opportunities that might otherwise be available to Enable. In response to sharp declines in demand for oil and gas as well as commodity prices resulting from the economic impact of COVID-19, many producers have significantly reduced previously anticipated drilling and production activities and may make additional reductions in the future. Decreased demand for commodities as a result of COVID-19 impacted the valuation of OGE Energy's


43

investment in Enable, resulting in an impairment charge in March 2020 that had a material adverse impact on OGE Energy's results of operations for the year ended December 31, 2020. Further, OGE Energy's operating cash flow is derived partially from cash distributions it receives from Enable. In response to current industry conditions, Enable reduced its dividend distribution by half, effective April 1, 2020. Prolonged decreased demand for commodities and/or further reductions in distributions from Enable could materially adversely affect OGE Energy's results of operations, financial condition and cash flows.

In addition, we cannot predict the ongoing impact that COVID-19 will have on our customers, suppliers, vendors and other business partners and each of their financial conditions; however, any material effect on these parties could adversely impact us. The impact of COVID-19 may also exacerbate the other risks discussed within this Form 10-K, any of which could have a material effect on us. As this situation continues and can change rapidly, additional impacts may arise that we are not aware of currently.

We face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements.
 
Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workers is higher than the national average. Over the next three years, 20 percent of our current employees will meet the eligibility requirements to retire. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business.

Certain provisions in our charter documents have anti-takeover effects.
 
Certain provisions of our certificate of incorporation and bylaws, as well as the Oklahoma corporation statute, may have the effect of delaying, deferring or preventing a change in control of OGE Energy. Such provisions, including those regulating the nomination of directors, limiting who may call special stockholders' meetings and eliminating stockholder action by written consent, together with the possible issuance of preferred stock of OGE Energy without stockholder approval, may make it more difficult for other persons, without the approval of our Board of Directors, to make a tender offer or otherwise acquire substantial amounts of our common stock or to launch other takeover attempts that a stockholder might consider to be in such stockholder's best interest.

We may be able to incur substantially more indebtedness, which may increase the risks created by our indebtedness.
 
The terms of the indentures governing our debt securities do not fully prohibit OGE Energy or OG&E from incurring additional indebtedness. If we are in compliance with the financial covenants set forth in our revolving credit agreements and the indentures governing our debt securities, we may be able to incur substantial additional indebtedness. If we incur additional indebtedness, the related risks that we now face may intensify.

 Any reductions in our credit ratings or changes in benchmark interest rates could increase our financing costs and the cost of maintaining certain contractual relationships or limit our ability to obtain financing on favorable terms.
 
We cannot assure you that any of the current credit ratings of the Registrants will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Our ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with our credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of our short-term borrowings, but a reduction in our credit ratings would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require us to post collateral or letters of credit.

Further, changes in benchmark interest rates, such as the United Kingdom's Financial Conduct Authority's announcement that it intends to phase out LIBOR by the end of 2021, could result in increased financing costs. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index. If the method for calculation of LIBOR changes, if LIBOR is no longer available or if lenders have increased costs due to changes in LIBOR, OGE Energy and OG&E may incur increases in interest rates on any borrowings and/or may need to renegotiate our credit facilities that utilize LIBOR as a factor in determining the interest rate to replace LIBOR with the new standard that is established.



44

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
 
We have revolving credit agreements for working capital, capital expenditures, acquisitions and other corporate purposes. The levels of our debt could have important consequences, including the following:

•the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms;
•a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations and future business opportunities; and
•our debt levels may limit our flexibility in responding to changing business and economic conditions.

We are exposed to the credit risk of our key customers and counterparties, and any material nonpayment or nonperformance by our key customers and counterparties could adversely affect our financial position, results of operations and cash flows.
 
We are exposed to credit risks in our generation and retail distribution operations. Credit risk includes the risk that counterparties who owe us money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected, and we could incur losses.

Item 1B. Unresolved Staff Comments.

None.



45

Item 2. Properties.

OG&E owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which included 15 generating stations with an aggregate capability of 7,120 MWs at December 31, 2020. The following table presents information with respect to OG&E's electric generating facilities, all of which are located in Oklahoma.
Fuel Capability 2020 Capacity Factor (A) Unit Capability (MW) Station Capability (MW)
Year Installed
Station & Unit Unit Design Type
Seminole 1 1971 Steam-Turbine Gas 10.5  % 485 
2 1973 Steam-Turbine Gas 26.4  % 500 
3 1975 Steam-Turbine Gas 21.0  % 498  1,483 
Muskogee 4 1977 Steam-Turbine Gas 14.8  % 423 
5 1978 Steam-Turbine Gas 14.0  % 442 
6 1984 Steam-Turbine Coal 30.8  % 503  1,368 
Sooner 1 1979 Steam-Turbine Coal 28.5  % 516 
2 1980 Steam-Turbine Coal 22.8  % 515  1,031 
Horseshoe Lake 5A (B) 1971 Combustion-Turbine Gas/Jet Fuel 1.1  % 33 
5B (B) 1971 Combustion-Turbine Gas/Jet Fuel 1.0  % 31 
6 1958 Steam-Turbine Gas 13.2  % 168 
7 1963 Steam-Turbine Gas 15.7  % 211 
8 1969 Steam-Turbine Gas 10.0  % 403 
9 2000 Combustion-Turbine Gas 24.6  % 45 
10 2000 Combustion-Turbine Gas 23.4  % 43  934 
Redbud (C) 1 2003 Combined Cycle Gas 52.3  % 154 
2 2003 Combined Cycle Gas 52.9  % 154 
3 2003 Combined Cycle Gas 53.1  % 153 
4 2003 Combined Cycle Gas 52.7  % 153  614 
Mustang 6 2018 Combustion-Turbine Gas 27.5  % 57 
7 2018 Combustion-Turbine Gas 23.7  % 57 
8 2017 Combustion-Turbine Gas 27.8  % 58 
9 2018 Combustion-Turbine Gas 28.3  % 58 
10 2018 Combustion-Turbine Gas 27.5  % 57 
11 2018 Combustion-Turbine Gas 26.6  % 57 
12 2018 Combustion-Turbine Gas 25.0  % 57  401 
McClain (D) 1 2001 Combined Cycle Gas 67.8  % 378  378 
Frontier 1 1989 Combined Cycle Gas 23.0  % 120  120 
River Valley 1 1991 Steam-Turbine Coal/Gas 28.2  % 160 
2 1991 Steam-Turbine Coal/Gas 31.1  % 160  320 
Total Generating Capability (all stations, excluding renewable) 6,649 
(A)2020 Capacity Factor = 2020 Net Actual Generation / (2020 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)). Capacity Factors are impacted by events that reduce Net Actual Generation such as planned outages.
(B)Represents units located at Tinker Air Force Base that are maintained by Horseshoe Lake.
(C)Represents OG&E's 51 percent ownership interest in the Redbud Plant.
(D)Represents OG&E's 77 percent ownership interest in the McClain Plant.



46

Renewable 2020 Capacity Factor (A) Unit Capability (MW) Station Capability (MW)
Year Installed Number of Units Fuel Capability
Station Location
Crossroads 2011 Canton, OK 98 Wind 39.9  % 2.3  228 
Centennial 2007 Laverne, OK 80 Wind 22.4  % 1.5  120 
OU Spirit 2009 Woodward, OK 44 Wind 33.8  % 2.3  101 
Mustang 2015 Oklahoma City, OK 90 Solar 20.3  % < 0.1 2 
Covington 2018 Covington, OK 4 Solar 26.1  % 2.3  10 
Choctaw Nation 2020 Durant, OK 2 Solar 20.3  % 2.5  5 
Chickasaw Nation 2020 Davis, OK 2 Solar 19.5  % 2.5  5 
Total Generating Capability (renewable) 471 
(A)2020 Capacity Factor = 2020 Net Actual Generation / (2020 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)). Capacity Factors are impacted by events that reduce Net Actual Generation such as planned outages.

At December 31, 2020, OG&E's transmission system included: (i) 402 substations with a total capacity of 24.3 million kV-amps and 5,122 structure miles of lines in Oklahoma and (ii) 36 substations with a total capacity of 3.8 million kV-amps and 277 structure miles of lines in Arkansas. At December 31, 2020, OG&E's distribution system included: (i) 349 substations with a total capacity of 10.4 million kV-amps, 29,443 structure miles of overhead lines, 3,202 miles of underground conduit and 11,038 miles of underground conductors in Oklahoma and (ii) 29 substations with a total capacity of 1.0 million kV-amps, 2,788 structure miles of overhead lines, 338 miles of underground conduit and 669 miles of underground conductors in Arkansas.

During the three years ended December 31, 2020, both Registrants' gross property, plant and equipment (excluding construction work in progress) additions were $2.6 billion, and gross retirements were $390.2 million. These additions were provided by cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper), long-term borrowings and permanent financings. The additions during this three-year period amounted to 19.9 percent of gross property, plant and equipment (excluding construction work in progress) for both Registrants at December 31, 2020.

Item 3. Legal Proceedings.
 
In the normal course of business, the Registrants are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion, the Registrants have incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in the Registrants' financial statements. At the present time, based on currently available information, the Registrants believe that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to their financial statements and would not have a material adverse effect on the Registrants' financial position, results of operations or cash flows.

Item 4. Mine Safety Disclosures.

Not Applicable.


47


PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
OGE Energy's common stock is listed for trading on the New York Stock Exchange under the ticker symbol "OGE." At December 31, 2020, there were 13,188 holders of record of OGE Energy's common stock.

Currently, all of OG&E's outstanding common stock is held by OGE Energy. Therefore, there is no public trading market for OG&E's common stock.

Issuer Purchases of Equity Securities
 
None.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
 
The following combined discussion is separately filed by OGE Energy and OG&E. However, OG&E does not make any representations as to information related solely to OGE Energy or the subsidiaries of OGE Energy other than itself.

Introduction
 
OGE Energy is a holding company with investments in energy and energy services providers offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S. OGE Energy conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of OGE Energy and its wholly-owned subsidiaries, including OG&E, are included in OGE Energy's consolidated financial statements. All intercompany transactions and balances are eliminated in such consolidation. OGE Energy generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance.

OG&E. OGE Energy's electric utility operations are conducted through OG&E, which generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. OG&E's rates are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is a wholly-owned subsidiary of OGE Energy. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

Enable. OGE Energy's natural gas midstream operations segment represents OGE Energy's investment in Enable. The investment in Enable is held through wholly-owned subsidiaries and ultimately OGE Holdings. Enable is primarily engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns crude oil gathering assets in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama. At December 31, 2020, OGE Energy owned 111.0 million common units, or 25.5 percent, of Enable's outstanding units. Enable's general partner is equally controlled by OGE Energy and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, OGE Energy accounts for its interest in Enable using the equity method of accounting. For additional information on OGE Energy's equity investment in Enable and related party transactions, see Notes 5 and 6 within "Item 8. Financial Statements and Supplementary Data."

Enable's business is impacted by commodity prices which have declined and otherwise experienced significant volatility in recent years. Commodity prices impact the drilling and production of natural gas and crude oil in the areas served by Enable's systems, and the volumes on Enable's systems can be negatively impacted if producers decrease drilling and production in those areas served. Both Enable's gathering and processing segment and Enable's transportation and storage segment can be affected by drilling and production. Enable's gathering and processing segment primarily serves producers, and many producers utilize the services provided by Enable's transportation and storage segment. A decrease in volumes on Enable's systems due to a decrease in drilling or production by Enable's producer customers could decrease the cash flows from Enable's systems. In addition, Enable's processing arrangements expose them to commodity price fluctuations. A portion of


48

OGE Energy's earnings and operating cash flows depend on the performance of, and distributions from, Enable. As disclosed in this Form 10-K, Enable is subject to a number of risks, including contract renewal risks, the reliance on the drilling and production decisions of others and the volatility of natural gas, NGLs and crude oil prices. The effects of COVID-19, including negative impacts on demand and commodity prices, could exacerbate these risks. If any of those risks were to occur, OGE Energy's business, financial condition, results of operations or cash flows could be materially adversely affected.

On February 12, 2021, Enable announced a quarterly dividend distribution of $0.16525 per unit on its outstanding common units, which is unchanged from the previous quarter. If cash distributions to Enable's unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. OGE Energy is entitled to 60 percent of those "incentive distributions."

On February 16, 2021, Enable entered into a definitive merger agreement with Energy Transfer, pursuant to which, and subject to the conditions of the merger agreement, all outstanding common units of Enable will be acquired by Energy Transfer in an all-equity transaction. Under the terms of the merger agreement, Enable's common unitholders, including OGE Energy, will receive 0.8595 of one common unit representing limited partner interests in Energy Transfer for each common unit of Enable. The transaction is anticipated to close in 2021. The transaction is subject to the receipt of the required approvals from the holders of a majority of Enable's common units, anti-trust approvals and other customary closing conditions. Assuming the transaction closes, OGE Energy will own approximately three percent of Energy Transfer's outstanding limited partner units in lieu of the 25.5 percent interest in Enable that it currently owns.
Overview
 
Strategy
 
OGE Energy's purpose is to energize life, providing life-sustaining and life-enhancing products and services, while honoring its commitment to strengthen communities. Its business model is centered around growth and sustainability for employees (internally referred to as "members"), communities and customers and the owners of OGE Energy, its shareholders.
 
OGE Energy is focused on:

•continuing to deliver top-quartile safety results, while enabling members to deliver improved value to their communities, customers and shareholders;
•transforming the customer experience with the right balance of personalized interaction and technology that allows our customers to self-serve;
•providing safe, reliable energy to the communities and customers it serves, with a particular focus on enhancing the value of the grid by improving reliability and resiliency;
•leading economic development and job growth by attracting new and diverse businesses to improve the infrastructure of the communities in Oklahoma and Arkansas;
•ensuring the necessary mix of generation resources to meet the long-term capacity needs of our customers, with a progressively cleaner generation portfolio;
•continuing focus on innovation, intellectual curiosity and executing with excellence in order to maintain customer rates that are some of the most affordable in the country;
•delivering on earnings commitments to shareholders to enhance access to lower-cost debt and equity capital that is needed to deploy infrastructure for the long-term economic health of its communities;
•having strong regulatory and legislative relationships, built on integrity, for the long-term benefit of our customers, communities, shareholders and members; and
•developing and growing our members to be able to provide a greater contribution to the company's success, while also improving their own lives.

OGE Energy is focused on creating long-term shareholder value by targeting the consistent growth of earnings per share of five percent at the electric utility, underscored by a strategy of investing in lower risk infrastructure projects that improve the economic vitality of the communities it serves in Oklahoma and Arkansas. OGE Energy utilizes cash distributions from its natural gas midstream operations segment to help fund its electric utility capital investments. OGE Energy's financial objectives also include maintaining investment grade credit ratings and providing a strong and reliable dividend for shareholders.

OGE Energy's long-term sustainability is predicated on providing exceptional customer experiences, investing in grid improvements and increasingly cleaner generation resources, environmental stewardship, strong governance practices and caring for and supporting its members and communities.


49


Recent Developments

COVID-19 Pandemic

In March 2020, the World Health Organization declared the outbreak of COVID-19 as a pandemic, which continues to spread throughout the U.S. and world. In an effort to contain COVID-19 or slow its spread, the U.S. federal, state and local governments enacted various measures, including orders to close or place restrictions on businesses not deemed "essential," enact "shelter in place" restrictions on residents and practice social distancing when engaging in essential activities. The COVID-19 outbreak has adversely impacted global markets and activity, including the energy industry, and it is impossible to predict the ultimate impact of the COVID-19 pandemic, as the situation continues to evolve. In Oklahoma City, OG&E's largest service territory, the mayor's "shelter in place" order required residents to stay home except for certain "essential" activities and closed down restaurant dining rooms, personal care services and other businesses that posed a high risk for spreading COVID-19. The order was effective from March 16, 2020 to April 30, 2020. Beginning May 1, 2020, Oklahoma City began its phased "re-opening," and there are currently no city-wide or state-wide "shelter in place" restrictions.

The Registrants' current and potential future responses to the COVID-19 impacts on their employees, customers and shareholders are further discussed below.

•The Registrants' top priority is to protect their employees and their families, as well as their customers. The Registrants are taking all precautionary measures as directed by health authorities and local and national governments. The Registrants continue to monitor the outbreak of COVID-19 and whether any occupancy reductions or closures are necessary to help ensure the health and safety of their employees and customers. The Registrants are also monitoring the status and availability of vaccinations in their service territories. In order to promote the safety of the Registrants' employees and the continuity of utility service, the Registrants implemented health-screening processes and increased sanitation efforts at their facilities and secured additional personal protective equipment, among other additional measures taken. The OCC and the APSC both issued accounting orders allowing the Registrants to defer these incremental costs incurred for recovery.
•As a precautionary measure in order to increase the Registrants' cash positions and preserve financial flexibility in light of current uncertainty resulting from the COVID-19 pandemic, in April 2020, OGE Energy entered into a one-year $75.0 million term loan agreement, and OG&E issued $300.0 million in senior notes. The term loan was fully repaid in September 2020.
•In March 2020, President Trump signed into U.S. federal law the Coronavirus Aid, Relief, and Economic Security Act, or the "CARES Act," which is aimed at addressing the economic disruption resulting from the COVID-19 pandemic and providing certain tax relief to businesses in the U.S. The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of the employer portion of FICA payroll taxes, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations and technical corrections to tax depreciation methods for qualified improvement property. The Registrants concluded that the financial impact of the provisions they adopted are immaterial.
•OG&E voluntarily suspended all disconnects for nonpayment, effective March 16, 2020, and on June 25, 2020 announced that it would reinstate disconnects for nonpayment in Oklahoma, effective July 6, 2020. OG&E also announced that it will provide broad payment options to customers who repay their past due balances, including a six-month installment plan and the Average Monthly Billing plan which would spread past due balances over a 12-month period. OG&E adjusted its reserve on accounts receivable as of December 31, 2020 in light of the current expected credit loss model (ASU 2016-13) and the COVID-19 pandemic. The adjustment, which was $1.3 million, incorporated concerns of continued slower customer payment due to unemployment. OG&E deferred this credit reserve amount to a regulatory asset, as both the OCC and the APSC issued accounting orders allowing OG&E to seek recovery of incremental bad debt resulting from COVID-19. OG&E will continue to monitor the reserve as it gains better clarity on the impacts of COVID-19 on its customers and business.
•Beginning in March 2020, oil and natural gas commodity prices have experienced extreme volatility, primarily attributable to decreased demand resulting from the COVID-19 pandemic and the actions of the Organization of Petroleum Exporting Countries and other oil exporting nations. On April 1, 2020, Enable announced its plan to reduce its quarterly distributions to its shareholders by 50 percent. This change in distribution, which should help strengthen Enable's balance sheet and increase its annualized cash flows, is supported by OGE Energy. OGE Energy does not foresee the need to access equity markets as a result of this reduction in distributions from Enable.



50

OGE Energy's Equity Investment in Enable

Effective March 31, 2020, OGE Energy estimated the fair value of its investment in Enable was below the book value and concluded the decline in value was not temporary due to the severity of the decline and recent rapid deterioration, as well as the near term future outlook, of the midstream oil and gas industry. Accordingly, OGE Energy recorded a $780.0 million impairment on its investment in Enable in March 2020. Further discussion can be found in Notes 5 and 7 within "Item 8. Financial Statements and Supplementary Data."

During the year ended December 31, 2020, Enable recorded goodwill, long-lived asset and equity method investment impairments and a loss on retirement that impacted OGE Energy's equity in earnings of unconsolidated affiliates, as adjusted for basis differences. Further discussion of these impacts can be found in "Results of Operations - OGE Holdings (Natural Gas Midstream Operations)."

February 2021 Extreme Cold Weather Event

In February 2021, OG&E's service territory experienced an unprecedented, prolonged, cold spell that resulted in record winter peak demand for electricity and extreme natural gas and purchased power prices. Estimates of the total regulatory asset for OG&E's fuel and purchased power costs that will be recorded are still under development but are expected to be in the range of $800.0 million to $1.0 billion. On February 24, 2021, OG&E submitted an application to the OCC requesting an intra-year fuel clause increase to be effective April 1, 2021, as well as requesting regulatory asset treatment at OG&E's weighted average cost of capital for the remaining fuel and purchased power costs associated with the unprecedented weather event. Further discussion of the anticipated financial impact can be found in "2021 Outlook" and "Short-term Debt and Credit Facilities" below and Note 16 within "Item 8. Financial Statements and Supplementary Data."

OG&E's Regulatory Matters

Completed regulatory matters affecting current period results are discussed in Note 16 within "Item 8. Financial Statements and Supplementary Data."

Summary of OGE Energy 2020 Operating Results Compared to 2019
OGE Energy's net loss was $173.7 million, or $0.87 per diluted share, in 2020 as compared to net income of $433.6 million, or $2.16 per diluted share, in 2019. The decrease in net income of $607.3 million, or $3.03 per diluted share, in 2020 as compared to 2019 is further discussed below.
•A net loss at OGE Holdings of $515.0 million, or $2.58 per diluted share of OGE Energy's common stock, during the year ended December 31, 2020 compared to net income of $81.4 million, or $0.41 per diluted share of OGE Energy's common stock, during the year ended December 31, 2019 was primarily due to a decrease in equity in earnings of Enable related to the impairment of OGE Energy's investment in Enable recorded in March 2020, partially offset by an income tax benefit related to the impairment charge and lower other expense. The decrease in equity in earnings of Enable was also impacted by OGE Energy's share of Enable's SESH equity method investment impairment recorded in September 2020, as adjusted for basis differences, and decreased net income from Enable's gathering and processing business resulting from lower natural gas gathered and processed volumes and lower average realized NGL and natural gas sales prices.
•A decrease in net income at OG&E of $10.8 million, or $0.04 per diluted share of OGE Energy's common stock, was primarily due to higher depreciation and amortization expense due to additional assets being placed into service, gross margin reductions from milder weather and COVID-19 impacts, higher income tax expense and higher interest expense driven by increased long-term debt outstanding. These decreases to net income were partially offset by increases to gross margin driven by recovery of additional assets placed into service through the expiration of the cogeneration credit rider and lower other operation and maintenance expense.
•A decrease in net income of other operations (holding company) of $0.1 million was primarily due to lower income tax benefit, partially offset by lower interest expense and higher other income.

A more detailed discussion regarding the financial performance for the year ended December 31, 2020 as compared to December 31, 2019 can be found under "Results of Operations" below. A discussion of the financial performance for the year ended December 31, 2019 compared to December 31, 2018 for OGE Energy and OG&E can be found within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of OGE Energy's 2019 Form 10-K and OG&E's 2019 Form 10-K, respectively.



51

2021 Outlook
 
Key assumptions for 2021 include:

OG&E

Before consideration of the February 2021 storm event as described below, OG&E is projected to earn approximately $352 million to $373 million, or $1.76 to $1.86 per average diluted share, in 2021 and is based on the following assumptions:

•normal weather patterns are experienced for the year;
•gross margin on revenues of approximately $1.553 billion to $1.569 billion, based on total retail load growth of 2.4 percent;
•operating expenses of approximately $991 million to $997 million, with operation and maintenance expenses comprising approximately 47.5 percent of the total;
•net interest expense of approximately $157 million to $159 million which assumes a $2.2 million allowance for borrowed funds used during construction reduction to interest expense;
•other income of approximately flat including approximately $4.8 million of allowance for equity funds used during construction; and
•an effective tax rate of approximately 11.3 percent.

OG&E has significant seasonality in its earnings. OG&E typically shows minimal earnings in the first and fourth quarters with a majority of its earnings in the third quarter due to the seasonal nature of air conditioning demand.

In February 2021, the OG&E service territory experienced an unprecedented, prolonged, cold spell that resulted in record winter peak demand for electricity and extreme natural gas and purchased power prices. In 2021, OG&E expects increased retail margins of approximately three to four cents per average diluted share related to the increased demand for electricity associated with the February cold spell.

OG&E's natural gas costs for the month of February 2021 exceeded the total cost for all of 2020. Fuel and purchased power costs are recovered through OG&E's Oklahoma and Arkansas fuel adjustment clauses. Estimates of the total regulatory asset for fuel and purchased power costs that will be recorded are still under development but are expected to be in the range of $800.0 million to $1.0 billion. OGE Energy has secured a commitment for $1.0 billion in additional short-term financing to provide additional liquidity to help cover these increased fuel and purchased power costs. In 2021, OG&E expects to incur approximately three to four cents per share related to incremental financing costs.

For approximately 58,000 guaranteed flat bill customers, representing approximately three percent of load, OG&E may be unable to seek recovery for the incremental fuel and purchased power costs that are included in customers' guaranteed flat bill agreements. In 2021, OG&E may incur approximately ten cents per average diluted share of potentially unrecoverable fuel and purchased power costs related to guaranteed flat bill agreements.

The potential impacts associated with the February 2021 cold spell are not reflected in OG&E's 2021 earnings guidance range of $1.76 to $1.86 per average diluted share.

OGE Holdings

Enable did not issue a 2021 earnings outlook due to the announced merger between Enable and Energy Transfer. While OGE Energy is not issuing earnings guidance for its ownership interest in Enable for 2021, it does expect to receive approximately $60 million to $73 million in cash distributions from its midstream investments in 2021.

Consolidated OGE Energy

OGE Energy is not issuing a 2021 consolidated earnings guidance due to Enable not issuing an earnings outlook; other consolidated assumptions include:

•approximately 200 million average diluted shares outstanding; and
•breakeven results projected at the holding company.



52

Non-GAAP Financial Measures

OGE Energy

"Ongoing earnings" and "ongoing earnings per average diluted share" are defined by OGE Energy as GAAP Net Income (Loss) and GAAP Earnings (Loss) per Average Diluted Share adjusted to exclude certain non-cash charges and the associated tax impacts. These financial measures excluded a pre-tax non-cash charge of $780.0 million, or $3.90 per average diluted share, associated with the impairment of OGE Energy's investment in Enable, which OGE Energy's management considers an unusual and infrequent event. Management believes that ongoing earnings and ongoing earnings per average diluted share provide a more meaningful comparison of earnings results and are more representative of OGE Energy's fundamental core earnings power. OGE Energy's management uses ongoing earnings and ongoing earnings per average diluted share internally for financial planning and analysis, for reporting of results to the Board of Directors and when communicating its earnings outlook to analysts and investors.

The following table presents reconciliations of ongoing earnings and ongoing earnings per average diluted share for the year ended December 31, 2020.
OG&E
(Electric Utility) 		OGE Holdings (Natural Gas Midstream Operations)
(B) 		Other Operations Consolidated OGE Energy Total
(In millions)
GAAP net income (loss) $ 339.4  $ (515.0) $ 1.9  $ (173.7)
Enable investment impairment charge (A) —  780.0  —  780.0 
Tax effect —  (190.4) —  (190.4)
Ongoing earnings $ 339.4  $ 74.6  $ 1.9  $ 415.9 
GAAP net income (loss) per average diluted share $ 1.70  $ (2.58) $ 0.01  $ (0.87)
Enable investment impairment charge per share (A) —  3.90  —  3.90 
Tax effect per share —  (0.95) —  (0.95)
Ongoing earnings per average diluted share $ 1.70  $ 0.37  $ 0.01  $ 2.08 
(A) Does not include a $16.9 million pre-tax charge recorded during 2020 for OGE Energy's share of Enable's goodwill, long-lived asset and equity method investment impairments and loss on retirements, as adjusted for basis differences.
(B) Tax effect and tax effect per share are calculated utilizing OGE Holdings' statutory tax rate for the year ended December 31, 2020.

OG&E

Gross margin is defined by OG&E as operating revenues less cost of sales. Cost of sales, as reflected on the income statement, includes fuel, purchased power and certain transmission expenses. Gross margin is a non-GAAP financial measure because it excludes depreciation and amortization and other operation and maintenance expenses. Expenses for fuel and purchased power are recovered through fuel adjustment clauses, and as a result, changes in these expenses are offset in operating revenues with no impact on net income. OG&E believes gross margin provides a more meaningful basis for evaluating its operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Board of Directors. OG&E's definition of gross margin may be different from similar terms used by other companies. Further, gross margin is not intended to replace operating revenues as determined in accordance with GAAP as an indicator of operating performance. For a reconciliation of gross margin to revenue, which is the most directly comparable financial measure calculated and presented in accordance with GAAP, for the years ended December 31, 2020 and 2019, see "OG&E (Electric Utility) Results of Operations" below.



53

The following table presents a reconciliation of gross margin to revenue included in the 2021 Outlook.
(In millions) Twelve Months Ended December 31, 2021
(A)
Operating revenues $ 2,303 
Cost of sales 742 
Gross margin $ 1,561 
(A) Based on the midpoint of OG&E earnings guidance for 2021.

Enable

Gross margin is defined by Enable as total revenues minus costs of natural gas and NGLs, excluding depreciation and amortization. Total revenues consist of the fees that Enable charges its customers and the sales price of natural gas and NGLs that Enable sells. The cost of natural gas and NGLs consists of the purchase price of natural gas and NGLs that Enable purchases. Enable deducts the cost of natural gas and NGLs from total revenues to arrive at a measure of the core profitability of their mix of fee-based and commodity-based customer arrangements. Gross margin allows for meaningful comparison of the operating results between Enable's fee-based revenues and Enable's commodity-based contracts which involve the purchase or sale of natural gas, NGLs and/or crude oil. In addition, OGE Energy believes gross margin allows for a meaningful comparison of the results of Enable's commodity-based activities across different commodity price environments because it measures the spread between the product sales price and cost of products sold. Enable's definition of gross margin may be different from similar terms used by other companies. Further, gross margin is not intended to replace operating revenues as determined in accordance with GAAP as an indicator of operating performance. For a reconciliation of gross margin to revenue, which is the most directly comparable financial measure calculated and presented in accordance with GAAP, for the years ended December 31, 2020 and 2019, see "OGE Holdings (Natural Gas Midstream Operations) Results of Operations" below.

Results of Operations
 
The following discussion and analysis presents factors that affected the Registrants' results of operations for the years ended December 31, 2020 and 2019 and the Registrants' financial positions at December 31, 2020 and 2019. The following information should be read in conjunction with the financial statements and notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.
OGE Energy Year Ended December 31,
(In millions except per share data) 2020 2019
Net income (loss) $ (173.7) $ 433.6 
Basic average common shares outstanding 200.1  200.1 
Diluted average common shares outstanding 200.1  200.7 
Basic earnings (loss) per average common share $ (0.87) $ 2.17 
Diluted earnings (loss) per average common share $ (0.87) $ 2.16 
Dividends declared per common share $ 1.58000  $ 1.50500 
 
Results by Business Segment
Year Ended December 31,
(In millions) 2020 2019
Net income (loss):
OG&E (Electric Utility) $ 339.4  $ 350.2 
OGE Holdings (Natural Gas Midstream Operations) (A) (515.0) 81.4 
Other operations (B) 1.9  2.0 
OGE Energy net income (loss) $ (173.7) $ 433.6 
(A)In March 2020, OGE Energy recorded a $780.0 million impairment on its investment in Enable, as further discussed in Notes 5 and 7 within "Item 8. Financial Statements and Supplementary Data."
(B)Other operations primarily includes the operations of the holding company and consolidating eliminations.



54

The following discussion of results of operations by business segment includes intercompany transactions that are eliminated in the OGE Energy consolidated financial statements.

OG&E (Electric Utility)
Year Ended December 31 (Dollars in millions)
2020 2019
Operating revenues $ 2,122.3  $ 2,231.6 
Cost of sales 644.6  786.9 
Other operation and maintenance 464.4  492.5 
Depreciation and amortization 391.3  355.0 
Taxes other than income 97.2  89.5 
Operating income 524.8  507.7 
Allowance for equity funds used during construction 4.8  4.5 
Other net periodic benefit expense 3.1  1.2 
Other income 5.0  6.7 
Other expense 2.6  6.9 
Interest expense 154.8  140.5 
Income tax expense 34.7  20.1 
Net income $ 339.4  $ 350.2 
Operating revenues by classification:
Residential $ 869.0  $ 891.1 
Commercial 479.4  503.1 
Industrial 197.3  223.0 
Oilfield 172.3  204.0 
Public authorities and street light 176.8  195.7 
Sales for resale 0.1  0.1 
System sales revenues 1,894.9  2,017.0 
Provision for rate refund 3.8  (0.9)
Integrated market 49.6  38.4 
Transmission 143.3  148.0 
Other 30.7  29.1 
Total operating revenues $ 2,122.3  $ 2,231.6 
Reconciliation of gross margin to revenue:
Operating revenues $ 2,122.3  $ 2,231.6 
Cost of sales 644.6  786.9 
Gross margin $ 1,477.7  $ 1,444.7 
MWh sales by classification (In millions)
Residential 9.5  9.7 
Commercial 6.3  6.5 
Industrial 4.2  4.5 
Oilfield 4.2  4.6 
Public authorities and street light 2.8  3.1 
System sales 27.0  28.4 
Integrated market 2.0  1.2 
Total sales 29.0  29.6 
Number of customers 867,389  857,754 
Weighted-average cost of energy per kilowatt-hour (In cents)
Natural gas 2.077  2.188 
Coal 1.821  2.029 
Total fuel 1.863  1.970 
Total fuel and purchased power 2.120  2.534 
Degree days (A)
Heating - Actual 3,303  3,771 
Heating - Normal 3,354  3,354 
Cooling - Actual 1,804  2,018 
Cooling - Normal 2,095  2,095 


55

(A)Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period.

OG&E's net income decreased $10.8 million, or 3.1 percent, in 2020 as compared to 2019. The following section discusses the primary drivers for the decrease in net income in 2020 as compared to 2019.

Operating revenues decreased $109.3 million, or 4.9 percent, in 2020 as compared to 2019, primarily due to reduced cost of sales which are recovered from customers.

Gross margin increased $33.0 million, or 2.3 percent, primarily driven by the below factors.
(In millions) $ Change
Price variance (A) $ 70.5 
New customer growth 10.8 
Quantity impacts (primarily weather) (B) (29.2)
Non-residential demand and related revenues (9.7)
Industrial and oilfield sales (9.3)
Other (0.1)
Change in gross margin (C) $ 33.0 
(A) Increased primarily due to the recovery of additional assets placed into service through the expiration of the cogeneration credit rider in the second half of 2019.
(B) Decreased primarily due to a 10.6 percent decrease in cooling degree days and a 12.4 percent decrease in heating degree days.
(C)Gross margin was impacted by COVID-19, particularly as seen in the negative impacts within industrial and oilfield sales and non-residential demand and related revenues.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC. OG&E's cost of sales decreased $142.3 million, or 18.1 percent, primarily driven by the below factors.
(In millions) $ Change % Change
Fuel expense (A) $ (9.0) (2.7) %
Purchased power costs:
Purchases from SPP (B)
(117.5) (39.6) %
Cogeneration (C)
(14.7) (100.0) %
Wind (0.3) (0.6) %
Other (0.3) (4.0) %
Transmission expense (0.5) (0.6) %
Change in cost of sales
$ (142.3)
(A)Decreased primarily due to lower fuel costs related to the generating assets utilized during 2020.
(B)Decreased primarily due to lower market prices as a result of decreased fuel costs for generators along with decreased MWhs purchased of 7.5 percent in 2020.
(C)Decreased due to the expiration of cogeneration contracts in 2019.



56

Other operation and maintenance expense decreased $28.1 million, or 5.7 percent, primarily driven by the below factors.
(In millions) $ Change % Change
Capitalized labor $ (15.6) (14.6) %
Contract technical and construction services (13.8) (27.6) %
Corporate overheads and allocations (7.2) (5.5) %
Other (5.3) (3.9) %
Materials and supplies (4.7) (18.7) %
Payroll and benefits 10.3  4.2  %
New expenses related to River Valley (A) 8.2  60.0  %
Change in other operation and maintenance expense (B) $ (28.1)
(A)Additional other operation and maintenance expenses related to the purchase of the River Valley plant are primarily recovered through a rider mechanism, as approved by the OCC in 2019.
(B)OG&E has been focused on reducing other operation and maintenance activities in light of COVID-19. Further, certain incremental expenses incurred by OG&E related to its COVID-19 response have been deferred and are included in the regulatory assets and liabilities table in Note 1 within "Item 8. Financial Statements and Supplementary Data."

Depreciation and amortization expense increased $36.3 million, or 10.2 percent, primarily due to additional assets being placed into service and depreciation expense for the Sooner Dry Scrubbers no longer being deferred to a regulatory asset.

Taxes other than income increased $7.7 million, or 8.6 percent, primarily due to increased ad valorem taxes.

Interest on long-term debt increased $14.5 million, or 10.5 percent, primarily due to increased long-term debt outstanding and interest expense for the Sooner Dry Scrubbers no longer being deferred to a regulatory asset.

Income tax expense increased $14.6 million, or 72.6 percent, primarily due to reduced tax credit generation, reduced amortization of net unfunded deferred taxes and higher pretax income.

OGE Holdings (Natural Gas Midstream Operations)
Year Ended December 31,
(In millions) 2020 2019
Operating revenues $ —  $ — 
Cost of sales —  — 
Other operation and maintenance 1.7  2.8 
Depreciation and amortization —  — 
Taxes other than income 0.4  0.4 
Operating loss (2.1) (3.2)
Equity in earnings (losses) of unconsolidated affiliates (A) (668.0) 113.9 
Other expense 2.9  8.6 
Income (loss) before taxes (673.0) 102.1 
Income tax expense (benefit) (158.0) 20.7 
Net income (loss) attributable to OGE Holdings $ (515.0) $ 81.4 
(A) In March 2020, OGE Energy recorded a $780.0 million impairment on its investment in Enable, as further discussed in Notes 5 and 7 within "Item 8. Financial Statements and Supplementary Data."

Reconciliation of Equity in Earnings (Losses) of Unconsolidated Affiliates

See Note 5 within "Item 8. Financial Statements and Supplementary Data" for the reconciliation of Enable's net income to OGE Energy's equity in earnings (losses) of unconsolidated affiliates and the reconciliation of the difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable (basis difference).



57

Enable Results of Operations and Operating Data

The following section presents summarized financial information of Enable for the years ended December 31, 2020 and 2019 and related discussion of the primary drivers for the changes in 2020 as compared to 2019.
Year Ended December 31,
(In millions) 2020 2019
Reconciliation of gross margin to revenue:
Total revenues $ 2,463  $ 2,960 
Cost of natural gas and NGLs 965  1,279 
Gross margin $ 1,498  $ 1,681 
Operating income $ 465  $ 569 
Net income $ 52  $ 360 

Year Ended December 31,
2020 2019
Natural gas gathered volumes - TBtu/d 4.26  4.56 
Natural gas processed volumes - TBtu/d (A) 2.19  2.53 
NGLs sold - MBbl/d (B) 128.40  131.59 
Crude oil and condensate gathered volumes - MBbl/d 124.84  128.46 
Transported volumes - TBtu/d 5.45  6.18 
(A)Includes volumes under third-party processing arrangements.
(B)Excludes condensate. NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

OGE Holdings' net loss of $515.0 million compared to net income of $81.4 million for 2020 and 2019, respectively, was primarily due to the impairment recorded in March 2020 on OGE Energy's investment in Enable, which is discussed in more detail in Notes 5 and 7 within "Item 8. Financial Statements and Supplementary Data." OGE Holdings' net loss in 2020 was also impacted by a decrease in Enable's net income of $308.0 million in 2020 as compared to 2019.

The following table presents summarized information regarding Enable's income statement changes for the year ended December 31, 2020, compared to the same period in 2019, and the corresponding impact those changes had on OGE Energy's equity in earnings of Enable. See Note 5 within "Item 8. Financial Statements and Supplementary Data" for further discussion of OGE Energy's equity investment in Enable. The decrease in Enable's net income was primarily due to the below factors.
(In millions) Income Statement Change at Enable Impact to OGE Energy's Equity in Earnings
Gross margin $ (183.0) $ (46.7)
Impairments of property, plant and equipment and goodwill (A) $ (58.0) $ 39.5 
Depreciation and amortization $ (13.0) $ 3.3 
Operation and maintenance, general and administrative (B) $ (10.0) $ 6.7 
Equity in earnings (losses) of equity method affiliate (C) $ (227.0) $ (12.0)
(A)Included in Enable's impairments of property, plant and equipment and goodwill is a $12.0 million goodwill impairment and a $16.0 million impairment for certain long-lived assets in their gathering and processing business segment. These certain long-lived assets are jointly-owned by Enable, which reduces the impairment's impact by 50 percent on OGE Energy's equity in earnings. OGE Energy recorded a $4.4 million pre-tax charge for its share of Enable's goodwill and long-lived asset impairments, as adjusted for basis differences.
(B)Included in Enable's operation and maintenance and general and administrative expenses is a $20.0 million loss on retirement of an Ark-La-Tex gathering system in their gathering and processing business segment. OGE Energy recorded a $1.0 million pre-tax charge for its share of Enable's loss on retirement, as adjusted for basis differences.
(C)Included Enable's equity in earnings (losses) of equity method affiliate is a $225.0 million impairment that Enable recorded on its SESH equity method investment. Enable estimated the fair value of this equity method investment was below the


58

carrying value at September 30, 2020 and concluded the decline in value was other than temporary due to the expiration of a transportation contract and the current status of renewal negotiations. OGE Energy recorded a $11.5 million pre-tax charge for its share of Enable's equity method investment impairment, as adjusted for basis differences.

Enable's gathering and processing business segment reported a decrease of $133.0 million in operating income. The following table presents summarized information regarding Enable's gathering and processing business segment income statement changes for 2020 as compared to 2019, and the corresponding impact those changes had on OGE Energy's equity in earnings of Enable. The decrease in Enable's gathering and processing business segment operating income was primarily due to the below factors.
(In millions) Income Statement Change at Enable Impact to OGE Energy's Equity in Earnings
Gross margin $ (185.0) $ (47.2)
Impairments of property, plant and equipment and goodwill (A) $ (58.0) $ 39.5 
Depreciation and amortization $ (9.0) $ 2.3 
Operation and maintenance, general and administrative (B) $ 14.0  $ 0.5 
(A) Included in Enable's impairments of property, plant and equipment and goodwill is a $12.0 million goodwill impairment and a $16.0 million impairment for certain long-lived assets in their gathering and processing business segment. These certain long-lived assets are jointly-owned by Enable, which reduces the impairment's impact by 50 percent on OGE Energy's equity in earnings. OGE Energy recorded a $4.4 million pre-tax charge for its share of Enable's goodwill and long-lived asset impairments, as adjusted for basis differences.
(B)    Included in Enable's operation and maintenance and general and administrative expenses is a $20.0 million loss on retirement of an Ark-La-Tex gathering system in their gathering and processing business segment. OGE Energy recorded a $1.0 million pre-tax charge for its share of Enable's loss on retirement, as adjusted for basis differences.

Gathering and processing gross margin decreased primarily due to the following:

•a decrease in natural gas gathering fees due to lower gathered volumes in the Anadarko and Arkoma Basins, inclusive of producer shut-ins in the Anadarko Basin that occurred during a portion of 2020, lower shortfall fees associated with the expiration of certain minimum volume commitments contracts in the Ark-La-Tex and Arkoma Basins and lower revenue associated with a 2019 amendment of certain minimum volume commitment contracts in the Arkoma Basin;
•a decrease in revenues from natural gas sales less the cost of natural gas due to lower average sales prices and lower sales volumes;
•a decrease in revenues from NGL sales less the cost of NGLs due to lower volumes and lower average market prices for NGL products;
•a decrease in processing service fees due to lower processed volumes under fee-based arrangements, partially offset by higher consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to an increase in retained volumes at lower average market prices as well as an increase in the recognition of certain annual minimum processing fees;
•a decrease in realized gains on natural gas, condensate and NGL derivatives;
•a decrease in changes in the fair value of natural gas, condensate and NGL derivatives;
•a decrease in intercompany management fees; and
•crude oil, condensate and produced water gathering revenues remained flat primarily due to a decrease in gathered crude oil volumes in the Williston Basin, offset by customer project reimbursements.

Enable's transportation and storage business segment reported an increase of $29.0 million in operating income. The following table presents summarized information regarding Enable's transportation and storage business segment income statement changes for 2020 as compared to 2019, and the corresponding impact those changes had on OGE Energy's equity in earnings of Enable. The increase in Enable's transportation and storage business segment operating income was primarily due to the below factors.


59

(In millions) Income Statement Change at Enable Impact to OGE Energy's Equity in Earnings
Gross margin $ 2.0  $ 0.5 
Operation and maintenance, General and administrative $ (24.0) $ 6.1 
Depreciation and amortization $ (4.0) $ 1.0 

Transportation and storage gross margin increased primarily due to the following:

•an increase in system management activities; and
•an increase in firm transportation and storage services due to an increase in recognized rates and the recognition of certain previously reserved revenue upon the settlement of the MRT rate case, partially offset by lower interstate contracted capacity and lower rates on certain contracts for intrastate service with power generators; partially offset by
•a decrease in volume-dependent transportation revenues due to lower off-system intrastate transportation rates and lower transported volumes due to decreased production activity in the Anadarko Basin, partially offset by the recognition of revenue upon the settlement of the MRT rate case;
•a decrease in natural gas storage inventory due to write-downs to lower of cost or net realizable value of natural gas storage inventories;
•a decrease in realized gain on natural gas derivatives; and
•a decrease in revenues from NGL sales less the cost of NGLs due to a decrease in average NGL prices and lower volumes.

OGE Holdings' income tax benefit was $158.0 million for 2020, as compared to income tax expense of $20.7 million in 2019. The change is primarily due to a tax benefit of $190.4 million related to the impairment recorded in March 2020 on OGE Energy's investment in Enable, partially offset by state deferred tax adjustments related to OGE Energy's investment in Enable.

Off-Balance Sheet Arrangement 

As of December 31, 2020, OG&E has a noncancellable operating lease with a purchase option, covering 780 rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to fuel expense and are recovered through OG&E's fuel adjustment clauses. At the end of the lease term, which is February 1, 2024, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $6.8 million.

Liquidity and Capital Resources

Cash Flows

OGE Energy
Year Ended December 31 (In millions)
2020 2019 $
Change 		%
Change
Net cash provided from operating activities (A) $ 712.8  $ 681.5  $ 31.3  4.6  %
Net cash used in investing activities (B) $ (654.9) $ (624.7) $ (30.2) 4.8  %
Net cash used in financing activities (C) $ (56.8) $ (151.1) $ 94.3  (62.4) %
(A)Increased primarily due to a decrease in payments for purchased power at OG&E.
(B)Increased primarily due to increased reliability projects, partially offset by environmental projects at OG&E that were completed and placed into service in 2019 as well as fewer OG&E plant outages in 2020.
(C)Decreased primarily due to the payment of long-term debt by OG&E in January 2019, partially offset by a decrease in borrowings of short-term debt.

Working Capital
 
Working capital is defined as the difference in current assets and current liabilities. OGE Energy's working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to


60

and the timing of collections from OG&E's customers, the level and timing of spending for maintenance and expansion activity, inventory levels and fuel recoveries. The following discussion addresses changes in OGE Energy's working capital balances at December 31, 2020 compared to December 31, 2019.

Fuel Inventories decreased $9.8 million, or 21.2 percent, primarily due to decreased coal inventory.

Materials and Supplies increased $25.6 million, or 28.3 percent, primarily due to increased inventory acquired for upcoming projects.

Fuel Clause Under Recoveries decreased $39.5 million and Fuel Clause Over Recoveries increased $23.8 million, primarily due to increased collections from OG&E customers and lower fuel costs.

Other Current Assets increased $16.8 million, or 68.9 percent, primarily due to an increase in under-recovered riders and SPP transmission formula rate.
Short-term Debt decreased $17.0 million, or 15.2 percent, primarily due to funds for operational needs. OGE Energy borrows on a short-term basis, as necessary, by the issuance of commercial paper and borrowings under its revolving credit agreements and term credit agreement.

Accounts Payable increased $56.6 million, or 29.0 percent, primarily due to accruals related to storm restoration activity in the fourth quarter and timing of vendor payments.

Accrued Taxes increased $13.8 million, or 32.9 percent, primarily due to the deferment of the employer portion of FICA payroll taxes as allowed by the CARES Act and an increase in tax accruals related to ad valorem and income taxes.

Accrued Compensation decreased $9.5 million, or 23.4 percent, primarily due to lower accruals for incentive compensation in 2020 and labor accrued but not paid due to timing of pay periods.

Other Current Liabilities decreased $31.5 million, or 48.3 percent, primarily due to changes in amounts owed to OG&E customers which includes an $18.9 million reduction in SPP reserves related to the transmission formula rate and decreased over-recovered riders.

2020 Capital Requirements, Sources of Financing and Financing Activities
 
OGE Energy's total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $650.6 million, and contractual obligations, net of recoveries through fuel adjustment clauses, were $0.9 million, resulting in total net capital requirements and contractual obligations of $651.5 million in 2020. This compares to net capital requirements of $885.6 million and net contractual obligations of $12.0 million totaling $897.6 million in 2019.

In 2020, OGE Energy's primary sources of capital were cash generated from operations, proceeds from the issuance of long- and short-term debt and distributions from Enable. Changes in working capital reflect the seasonal nature of OGE Energy's business, the revenue lag between billing and collection from customers and fuel inventories. See "Working Capital" for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.

The Dodd-Frank Act

Derivative instruments have been used at times in managing OG&E's commodity price exposure. The Dodd-Frank Act, among other things, provides for regulation by the Commodity Futures Trading Commission of certain commodity-related contracts. Although OG&E qualifies for an end-user exception from mandatory clearing of commodity-related swaps, these regulations could affect the ability of OG&E to participate in these markets and could add additional regulatory oversight over its contracting activities.

Future Capital Requirements

OGE Energy's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes. OGE Energy generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings.


61


Capital Expenditures
 
The following table presents OGE Energy's estimates of capital expenditures for the years 2021 through 2025. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate OGE Energy's businesses) plus capital expenditures for known and committed projects. Estimated capital expenditures for Enable are not included.
(In millions) 2021 2022 2023 2024 2025 Total
Transmission $ 80  $ 110  $ 115  $ 105  $ 125  $ 535 
Oklahoma distribution 300  290  265  300  300  1,455 
Arkansas distribution 25  20  20  20  20  105 
Generation 100  85  125  125  130  565 
Oklahoma Grid Advancement 170  180  185  185  185  905 
Subscription Solar Plan 10  20  20  20  20  90 
Other 65  80  80  80  80  385 
Total $ 750  $ 785  $ 810  $ 835  $ 860  $ 4,040 

Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets, will be evaluated based upon their impact upon achieving OGE Energy's financial objectives. The continued progression of, and global response to, the COVID-19 outbreak increases the risk of delays in construction activities and equipment deliveries related to OGE Energy's capital projects, including potential delays in obtaining permits from government agencies, resulting in potential deferral of capital expenditures.

Contractual Obligations
 
The following table presents OGE Energy's contractual obligations at December 31, 2020. See the statements of capitalization and Notes 4 and 15 within "Item 8. Financial Statements and Supplementary Data" for additional information.
(In millions) 2021 2022-2023 2024-2025 After 2025 Total
Maturities of long-term debt $ —  $ —  $ —  $ 3,529.8  $ 3,529.8 
Operating lease obligations:  
Railcars 2.4  4.5  0.2  —  7.1 
Wind farm land leases 2.9  5.8  6.0  31.7  46.4 
Other leases 1.0  0.5  —  —  1.5 
Total operating lease obligations 6.3  10.8  6.2  31.7  55.0 
Purchase obligations and commitments:          
Minimum purchase commitments 72.5  100.8  62.6  307.4  543.3 
Expected wind purchase commitments 55.2  111.6  113.5  317.0  597.3 
Long-term service agreement commitments 2.4  10.3  66.3  83.5  162.5 
Total purchase obligations and commitments 130.1  222.7  242.4  707.9  1,303.1 
Total contractual obligations 136.4  233.5  248.6  4,269.4  4,887.9 
Amounts recoverable through fuel adjustment clause (A) (130.1) (216.9) (176.3) (624.4) (1,147.7)
Total OGE Energy contractual obligations, net $ 6.3  $ 16.6  $ 72.3  $ 3,645.0  $ 3,740.2 
(A)Includes expected recoveries of costs incurred for OG&E's railcar operating lease obligations, OG&E's minimum fuel purchase commitments and OG&E's expected wind purchase commitments.
 
The actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E's railcar leases shown above) and certain purchased power costs are passed on to OG&E's customers through fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of minimum fuel purchase commitments of OG&E noted above may increase capital requirements, such costs are recoverable through fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC.



62

Pension and Postretirement Benefit Plans
 
At December 31, 2020, 43.2 percent of the Pension Plan investments were in listed common stocks with the balance primarily invested in corporate fixed income, other securities and U.S. Treasury notes and bonds as presented in Note 13 within "Item 8. Financial Statements and Supplementary Data." During 2020, actual returns on the Pension Plan were $77.0 million, compared to expected return on plan assets of $37.6 million. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, decreased. Funding levels are dependent on returns on plan assets and future discount rates. OGE Energy made a $20.0 million contribution to its Pension Plan in both 2020 and 2019. In January 2021, OGE Energy made a $40.0 million contribution to its Pension Plan and has not determined whether it will need to make any additional contributions to the Pension Plan in 2021. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.

The following table presents the status of OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans at December 31, 2020 and 2019. These amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss (except OG&E's portion, which is recorded as a regulatory asset as discussed in Note 1 within "Item 8. Financial Statements and Supplementary Data") in the balance sheets. The amounts in Accumulated Other Comprehensive Loss and those recorded as a regulatory asset represent a net periodic benefit cost to be recognized in the statements of income in future periods.
Pension Plan Restoration of Retirement
Income Plan 		Postretirement
Benefit Plans
December 31 (In millions)
2020 2019 2020 2019 2020 2019
Benefit obligations $ 654.6  $ 616.1  $ 7.8  $ 10.3  $ 144.5  $ 136.5 
Fair value of plan assets 570.3  530.3  —  —  47.6  47.0 
Funded status at end of year $ (84.3) $ (85.8) $ (7.8) $ (10.3) $ (96.9) $ (89.5)

Common Stock Dividends
OGE Energy's dividend policy is reviewed by the Board of Directors at least annually and is based on numerous factors, including management's estimation of the long-term earnings power of its businesses. At OGE Energy's September 2020 board meeting, the Board of Directors approved management's recommendation of a four percent increase in the quarterly dividend rate to $0.4025 per share from $0.3875 per share effective in October 2020.

Financing Activities and Future Sources of Financing

Management expects that cash generated from operations, proceeds from the issuance of long- and short-term debt, proceeds from the sales of common stock to the public through OGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings and distributions from Enable will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. OGE Energy utilizes short-term borrowings (through a combination of bank borrowings and commercial paper) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged. As indicated above, as a precautionary measure in order to increase OGE Energy's cash position and preserve financial flexibility in light of uncertainty resulting from the COVID-19 pandemic, OGE Energy entered into a one-year $75.0 million term loan agreement in April 2020, which was repaid in September 2020. Further, OG&E issued $300.0 million in senior notes in April 2020. The disruption in the capital markets and the commercial paper markets caused by the COVID-19 outbreak could make additional financing more challenging, and there can be no assurance that OGE Energy will be able to obtain such financing on commercially reasonable terms or at all. In February 2021, OGE Energy entered into a $1.0 billion commitment letter for an unsecured term loan facility to provide additional liquidity to help cover the increased fuel and purchased power costs incurred by OG&E during the unprecedented cold weather event experienced in OG&E's service territory.

Short-Term Debt and Credit Facilities
 
OGE Energy borrows on a short-term basis, as necessary, by issuance of commercial paper and borrowings under its revolving credit agreements and term credit agreements.



63

OGE Energy has unsecured five-year revolving credit facilities totaling $900.0 million ($450.0 million for OGE Energy and $450.0 million for OG&E), which can also be used as letter of credit facilities. The following table presents information about OGE Energy's revolving credit agreements as of December 31, 2020.
(Dollars in millions)
December 31, 2020
Balance of outstanding supporting letters of credit $ 0.4 
Weighted-average interest rate of outstanding supporting letters of credit 1.00  %
Net available liquidity under revolving credit agreements $ 804.6 
Balance of cash and cash equivalents $ 1.1 

The following table presents information about OGE Energy's total short-term debt activity for the year ended December 31, 2020.
(Dollars in millions)
Year Ended December 31, 2020
Average balance of short-term debt $ 77.4 
Weighted-average interest rate of average balance of short-term debt 1.52  %
Maximum month-end balance of short-term debt $ 247.3 

See Note 12 within "Item 8. Financial Statements and Supplementary Data" for further discussion of the Registrants' short-term debt activity. Such activity includes: (i) during 2020, OGE Energy entered into and subsequently repaid a $75.0 million term loan agreement in response to COVID-19; (ii) in January 2021, the Registrants extended their respective revolving credit facilities' term for an additional year; and (iii) in January 2021, the Registrants entered into amendments for their respective revolving credit facilities which provides the option of extending their respective commitments for up to two additional one-year periods as well as addressed the phase out of LIBOR and the establishment of an alternative rate of interest.

On February 24, 2021, OGE Energy entered into a commitment letter with Wells Fargo and certain of its affiliates whereby Wells Fargo committed to provide an unsecured term loan facility in the aggregate principal amount of $1.0 billion. While borrowing availability still exists within the Registrants' credit facilities, the $1.0 billion commitment in additional short-term financing is expected to provide additional liquidity to help cover the increased fuel and purchased power costs incurred by OG&E during the February 2021 unprecedented cold weather event. For further discussion, see "Item 9B. Other Information." OGE Energy expects to have additional short-term debt outstanding in 2021 which will result in additional interest expense.

OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 2021 and ending December 31, 2022.

Issuance of Long-Term Debt

In April 2020, OG&E issued $300.0 million of 3.25 percent senior notes due April 1, 2030. The proceeds from the issuance were added to OG&E's general funds to be used for general corporate purposes, including to fund ongoing capital expenditures and working capital.

Security Ratings
  Moody's Investors Service Outlook S&P's Global Ratings Outlook Fitch Ratings Outlook
OG&E Senior Notes A3 Stable A- Stable A Stable
OG&E Commercial Paper P2 Stable A2 Stable F2 Stable
OGE Energy Senior Notes Baa1 Stable BBB+ Stable BBB+ Stable
OGE Energy Commercial Paper P2 Stable A2 Stable F2 Stable

Access to reasonably priced capital is dependent in part on credit and security ratings. Generally, lower ratings lead to higher financing costs. Pricing grids associated with OGE Energy's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of OGE Energy's short-term borrowings, but a reduction in OGE Energy's credit ratings would not result in any defaults or


64

accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require OGE Energy to post collateral or letters of credit.
A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency, and each rating should be evaluated independently of any other rating.

Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, abnormal weather, load growth, commodity prices, acquisitions of other businesses and/or development of projects, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators.

Common Stock
OGE Energy does not expect to issue any common stock in 2021 from its Automatic Dividend Reinvestment and Stock Purchase Plan. See Note 10 within "Item 8. Financial Statements and Supplementary Data" for a discussion of OGE Energy's common stock activity.

Distributions by Enable
 
Pursuant to the Enable Limited Partnership Agreement, Enable made distributions of $91.7 million, $144.0 million and $141.2 million to OGE Energy during the years ended December 31, 2020, 2019 and 2018, respectively. As required by Enable's Limited Partnership Agreement and General Partner Agreement, respectively, the last permitted distribution date is 60 days after the close of each quarter, and the distribution deadline is five days following distributions by Enable. On April 1, 2020, Enable announced a 50 percent reduction to its quarterly distribution in order to strengthen its balance sheet and increase its annualized retained cash flow. OGE Energy does not expect any changes to its operations or foresee the need to access the equity markets as a result of Enable's action.
Critical Accounting Policies and Estimates
 
The financial statements and notes thereto contain information that is pertinent to Management's Discussion and Analysis. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Changes to these assumptions and estimates could have a material effect on the financial statements. The Registrants believe they have taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the Registrants that could result if actual results vary from the assumptions and estimates. 

In management's opinion, the areas where the most significant judgment is exercised for the Registrants include the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations, regulatory assets and liabilities, unbilled revenues and the allowance for uncollectible accounts receivable. For OGE Energy, significant judgment is also exercised in the determination of any impairment of equity method investments. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Audit Committee of OGE Energy's Board of Directors. The Registrants discuss their significant accounting policies, including those that do not require management to make difficult, subjective or complex judgments or estimates, in Note 1 within "Item 8. Financial Statements and Supplementary Data."

Pension and Postretirement Benefit Plans
 
OGE Energy has a Pension Plan that covers a significant amount of its employees, including OG&E's employees, hired before December 1, 2009. Effective December 1, 2009, OGE Energy's Pension Plan is no longer being offered to employees hired on or after December 1, 2009. OGE Energy also has defined benefit postretirement plans that cover a significant amount of its employees, including OG&E's employees. Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and the level of funding. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The Pension Plan rate assumptions are shown in Note 13 within "Item 8. Financial Statements and Supplementary Data." The assumed return on plan assets is based on management's expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be


65

paid. Funding levels are dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the Pension Plan.

 The following table presents the sensitivity of the Pension Plan funded status to these variables.
  Change Impact on Funded Status
Actual plan asset returns +/- 1 percent +/- $5.7 million
Discount rate +/- 0.25 percent +/- $11.9 million
Contributions +/- $10 million +/- $10.0 million
 
Income Taxes

The Registrants use the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change.
The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous. Interpretations and guidance surrounding income tax laws and regulations change over time. Accordingly, it is necessary to make judgments regarding income tax exposure. As a result, changes in these judgments can materially affect amounts the Registrants recognized in their financial statements. Tax positions taken by the Registrants on their income tax returns that are recognized in the financial statements must satisfy a more likely than not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information.

Commitments and Contingencies
 
In the normal course of business, the Registrants are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion, the Registrants have incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in the financial statements.

Asset Retirement Obligations
 
OG&E has recorded asset retirement obligations that are being accreted over their respective lives ranging from five to 68 years. The inputs used in the valuation of asset retirement obligations include the assumed life of the asset placed into service, the average inflation rate, market risk premium, the credit-adjusted risk free interest rate and the timing of incurring costs related to the retirement of the asset.

Regulatory Assets and Liabilities
 
OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.
 
OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates. Management continuously monitors the future recoverability of regulatory assets. When in management's judgement future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate.
 


66

Unbilled Revenues
 
OG&E recognizes revenue from electric sales when power is delivered to customers. OG&E measures its customers' metered usage and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues in the balance sheets and in Operating Revenues in the statements of income based on estimates of usage and prices during the period. At December 31, 2020, if the estimated usage or price used in the unbilled revenue calculation were to increase or decrease by one percent, this would cause a change in the unbilled revenues recognized of $0.5 million. At December 31, 2020 and 2019, Accrued Unbilled Revenues were $68.0 million and $64.7 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
 
Allowance for Uncollectible Accounts Receivable
 
Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is generally calculated by multiplying the last six months of electric revenue by the provision rate, which is based on a 12-month historical average of actual balances written off and is adjusted for current conditions and supportable forecasts as necessary. To the extent the historical collection rates, when incorporating forecasted conditions, are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. At December 31, 2020, if the provision rate were to increase or decrease by 10 percent, this would cause a change in the uncollectible expense recognized of $0.3 million. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable in the balance sheets and is included in Other Operation and Maintenance Expense in the statements of income. The allowance for uncollectible accounts receivable was $2.6 million and $1.5 million at December 31, 2020 and 2019, respectively.

OG&E adjusted its reserve on accounts receivable as of December 31, 2020 in light of COVID-19 pandemic impacts and deferred this credit reserve adjustment to a regulatory asset, as both the OCC and the APSC issued accounting orders allowing OG&E to seek recovery of incremental bad debt resulting from COVID-19, as further discussed in Note 16 within "Item 8. Financial Statements and Supplementary Data."

Impairment of Equity Method Investments

Investments in unconsolidated affiliates accounted for under the equity method are assessed for impairment when there are indicators of a loss in value, such as a lack of sustained earnings capacity or a current fair value less than the investment's carrying amount. When it is determined that an indicated impairment is other than temporary, an impairment charge is recognized for the difference between the investment's carrying value and its estimated fair value.

When determining whether a decline in value is other than temporary, management considers factors such as the duration and extent of the decline, the investee's financial condition and near-term prospects, and management's ability and intention to retain the investment for a period that allows for recovery. When estimating an investment's fair value, quoted market prices are utilized, as available, and other rights and privileges that are a feature or attribute of the investment security are considered, as appropriate. Different assumptions could affect the timing and the amount of an impairment of an investment in any period.

Effective March 31, 2020, OGE Energy estimated the fair value of its investment in Enable was below the book value and concluded the decline in value was not temporary due to the severity of the decline and the recent rapid deterioration, as well as the near term future outlook, of the midstream oil and gas industry. Accordingly, OGE Energy recorded a $780.0 million impairment on its investment in Enable in March 2020, which is included in Equity in Earnings (Losses) of Unconsolidated Affiliates in OGE Energy's 2020 income statement. Further discussion can be found in Notes 5 and 7 within "Item 8. Financial Statements and Supplementary Data."

Accounting Pronouncements
See Note 2 within "Item 8. Financial Statements and Supplementary Data" for discussion of current accounting pronouncements that are applicable to the Registrants.



67

Commitments and Contingencies
 
In the normal course of business, the Registrants are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion, the Registrants have incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in the financial statements. At the present time, based on available information, the Registrants believe that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to their financial statements and would not have a material adverse effect on their financial position, results of operations or cash flows. See Notes 15 and 16 within "Item 8. Financial Statements and Supplementary Data" and "Item 3. Legal Proceedings" for further discussion of the Registrants' commitments and contingencies.
 
Environmental Laws and Regulations
 
The activities of OG&E are subject to numerous stringent and complex federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways, including the handling or disposal of waste material, planning for future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions or pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of the Registrants' operations are in substantial compliance with current federal, state and local environmental standards.

President Biden has taken a number of actions that affect environmental regulations adopted by the Trump administration, including issuance of an executive order that instructs the EPA and other executive agencies to review certain rules that affect OG&E. OG&E is monitoring these actions which are in the preliminary stages of being implemented. At this point in time, the impacts of these actions on the Registrants' results of operations, if any, cannot be determined with any certainty.

Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
 
Air

Federal Clean Air Act Overview

OG&E's operations are subject to the Federal Clean Air Act as amended and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units and also impose various monitoring and reporting requirements. Such laws and regulations may require that OG&E obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations or install emission control equipment. OG&E likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions.

Cross-State Air Pollution Rule

On September 7, 2016, the EPA finalized an update to the 2011 Cross-State Air Pollution Rule. The new rule applies to ozone-season NOX emissions from power plants in 22 eastern states (including Oklahoma). The rule utilizes a cap and trade program for NOX emissions and went into effect on May 1, 2017 in Oklahoma. The 2016 rule reduces the 2011 Cross-State Air Pollution Rule emissions cap for all of OG&E's coal and gas facilities (except the River Valley and Frontier facilities which were not owned by OG&E until 2019) by 47 percent combined. OG&E and numerous other parties filed petitions for judicial and administrative review of the 2016 rule. On September 13, 2019, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion that partially remanded the Cross-State Air Pollution Rule update and also deferred a decision on our challenges to the rule pending an EPA review and decision on a separate administrative petition that we filed. Subsequently, all of OG&E's judicial challenges were voluntarily dismissed, but the administrative petitions for reconsideration remain pending at the EPA. On October 30, 2020, the EPA published a proposed rule to revise the 2016 update rule and address the 2019 remand. The EPA did not propose any additional reductions in the emissions budget for Oklahoma based on a preliminary


68

determination that the state does not cause or contribute to nonattainment of the ambient air quality standards in the relevant downwind areas. OG&E subsequently filed comments to the proposal.

OG&E continues to monitor these processes and their possible impact on its operations but, at this time, cannot determine with any certainty whether they will cause a material impact to OG&E's financial results. OG&E is in compliance with the 2016 rule requirements which remain in effect. OG&E does not anticipate, at this time, additional capital expenditures for compliance with the 2016 rule.

Hazardous Air Pollutants Emission Standards

On February 16, 2012, the EPA published the final MATS rule regulating the emissions of certain hazardous air pollutants from electric generating units. OG&E complied with the MATS rule by the April 16, 2016 deadline that applied to OG&E's coal units. On April 16, 2020, the EPA released a final rule which reconsidered certain elements of the 2012 rule in response to litigation in the D.C. Circuit Court. In the final rule, the EPA concluded that it is not "appropriate and necessary" to regulate MATS-related emissions from coal-fired units. Nonetheless, the EPA retained the emissions limits that were established in the 2012 rule, which remains in effect today. Petitions for judicial review of the final May 2020 rule have been filed at the D.C. Circuit Court.

National Ambient Air Quality Standards

The EPA is required to set NAAQS for certain pollutants considered to be harmful to public health or the environment. The Clean Air Act requires the EPA to review each NAAQS every five years. As a result of these reviews, the EPA periodically has taken action to adopt more stringent NAAQS for those pollutants. If any areas of Oklahoma were to be designated as not attaining the NAAQS for a particular pollutant, OG&E could be required to install additional emission controls on its facilities to help the state achieve attainment with the NAAQS. As of December 31, 2020, no areas of Oklahoma had been designated as non-attainment for pollutants that are likely to affect OG&E's operations.

The EPA proposed to designate part of Muskogee County, in which OG&E's Muskogee Power Plant is located, as non-attainment for the 2010 SO2 NAAQS on March 1, 2016, even though nearby monitors indicated compliance with the NAAQS. The proposed designation was based on modeling that did not reflect the conversion of two of the coal units at Muskogee to natural gas. The State of Oklahoma's monitoring from 2017-2019 indicated that ambient SO2 emissions in the area are well within the NAAQS. On December 21, 2020, the EPA published in the Federal Register its final designation of the relevant area in Muskogee County as attainment/unclassifiable.

Climate Change and Greenhouse Gas Emissions
There is continuing discussion and evaluation of possible global climate change in certain regulatory and legislative arenas. The focus is generally on emissions of greenhouse gases, including CO2, sulfur hexafluoride and methane, and whether these emissions are contributing to the warming of the earth's atmosphere. On November 4, 2020, the U.S. officially withdrew from the United Nations' "Paris Agreement" on climate change. Newly elected President Biden announced on January 20, 2021 that the U.S. would rejoin the agreement. In addition, President Biden has recently stated that a goal of his administration is to see the electric power industry fully decarbonized by 2035, although details of the goal are not available. Such decisions may result in future additional greenhouse gas emissions reductions in the U.S.; however, it is not possible to determine what the U.S. standards for greenhouse gas emissions will be in the future or the extent to which these commitments will be implemented through the Clean Air Act or any other existing statutes and new legislation.
If legislation or regulations are passed at the federal or state levels in the future requiring mandatory reductions of CO2 and other greenhouse gases on OG&E's facilities, this could result in significant additional compliance costs that would affect OG&E's future financial position, results of operations and cash flows if such costs are not recovered through regulated rates. Several states outside the area where OG&E operates have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.
OG&E's current business strategy has resulted in reduced carbon dioxide emissions by over 40 percent compared to 2005 levels, and during the same period, emissions of ozone-forming NOx have been reduced by approximately 75 percent and emissions of SO2 have been reduced by approximately 90 percent. OG&E expects to further reduce carbon dioxide emissions to 50 percent of 2005 levels by 2030. To comply with the EPA's MATS rule and Regional Haze Rule FIP, OG&E converted two coal-fired generating units at the Muskogee Station to natural gas, among other measures. OG&E's deployment of Smart Grid technology helps to reduce the peak load demand. OG&E is also deploying more renewable energy sources that do not emit


69

greenhouse gases. OG&E's service territory borders one of the nation's best wind resource areas, and OG&E has leveraged its geographic position to develop renewable energy resources and completed transmission investments to deliver the renewable energy. The SPP has authorized the construction of transmission lines capable of bringing renewable energy out of the wind resource areas in western Oklahoma, the Texas Panhandle and western Kansas to load centers by planning for more transmission to be built in the area. In addition to increasing overall system reliability, these new transmission resources should provide greater access to additional wind resources that are currently constrained due to existing transmission delivery limitations.
Regional Haze Regulation - Second Planning Period

In January 2017, the EPA finalized a rule that would revise certain provisions of the Regional Haze Rule. Notably, the EPA extended the SIP deadline for the second Regional Haze implementation period by three years to 2021 and made changes to the provisions for impacts to national parks and other protected wilderness areas. Petitions for Reconsideration to the EPA were filed by industry groups. While not acting on the petitions, the EPA announced on January 17, 2018 that it intends to commence a notice-and-comment rulemaking revisiting certain aspects of the rule. During 2019, the EPA released technical resources to assist states in developing SIPs, including a significant non-binding guidance document and updated atmospheric modeling which will allow states to better account for international emissions affecting regional haze in the U.S. On July 1, 2020, the ODEQ notified OG&E that the Horseshoe Lake generating units are to be included in the state's evaluation of visibility impairment impacts to the Wichita Mountains. OG&E conducted an analysis of all potential control measures for NOx on these units and submitted it to the ODEQ on September 15, 2020. The ODEQ will identify any cost-effective control measures in a Regional Haze SIP, to be submitted to the EPA for approval by July 31, 2021. It is unknown at this time what the outcome, or any potential material impacts, will be from the evaluations by OG&E, the ODEQ and the EPA.

Endangered Species

Certain federal laws, including the Bald and Golden Eagle Protection Act, the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats. If such species are located in an area in which OG&E conducts operations, or if additional species in those areas become subject to protection, OG&E's operations and development projects, particularly transmission, wind or pipeline projects, could be restricted or delayed, or OG&E could be required to implement expensive mitigation measures.

Vegetation Management

On July 10, 2020, the U.S. Department of Agriculture – Forest Service published a final rule which updates procedures for creating operating plans and agreements for powerline facility maintenance and vegetation management within and abutting the linear boundary of a special use authorization for a powerline facility within Forest Service lands. This rule codifies the memorandum of understanding between utilities such as OG&E and the Forest Service regarding vegetation management best practices. All companies will be required to have an approved operating plan or agreement with the Forest Service. OG&E will be required to submit a draft operating plan to the Forest Service by August 10, 2023 for ongoing maintenance and vegetation management activities located within the Ozark National Forest in Arkansas.

Waste

OG&E's operations generate wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 as well as comparable state laws which impose detailed requirements for the handling, storage, treatment and disposal of waste.

In 2015, the EPA finalized a rule under the Federal Resource Conservation and Recovery Act for the handling and disposal of coal combustion residuals or coal ash. The rule regulates coal ash as a solid waste rather than a hazardous waste, which would have made the management of coal ash more costly. In August 2019, the EPA proposed revisions to the 2015 coal ash rule in response to the D.C. Circuit Court of Appeals issuing a decision regarding the ongoing Coal Combustion Residuals litigation. The proposed changes do not appear to be material to OG&E at this time. OG&E completed the clean closure of one regulated inactive coal ash impoundment in August 2019.

On June 28, 2018, the EPA approved the State of Oklahoma's application for a state coal ash permitting program that will operate in lieu of the federal coal ash program promulgated under the Federal Resource Conservation and Recovery Act. On September 26, 2018, a citizen suit was filed against the EPA in the U.S. District Court in the District of Columbia


70

concerning the final approval, which was decided upon in the EPA's favor on April 15, 2020 and has subsequently been appealed.

OG&E currently recycles and provides approximately 97 percent of its ash to the concrete and cement industries for use as a component within their products and, in the last five years, has diverted more than 1.3 million tons of ash from landfills. Using fly ash in this way enables aggregate manufacturers to minimize their impact on the environment by avoiding the need to extract and process other natural resources.

OG&E has sought and will continue to seek pollution prevention opportunities and to evaluate the effectiveness of its
waste reduction, reuse and recycling efforts. In 2020, OG&E obtained refunds of $2.6 million from the recycling of scrap metal,
salvaged transformers and used transformer oil. This figure does not include the additional savings gained through the reduction
and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials. Similar savings
are anticipated in future years.

Water

OG&E's operations are subject to the Federal Clean Water Act and comparable state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters.
The EPA issued a final rule on May 19, 2014 to implement Section 316(b) of the Federal Clean Water Act, which requires that power plant cooling water intake structure location, design, construction and capacity reflect the best available technology for minimizing their adverse environmental impact via the impingement and entrainment of aquatic organisms. The ODEQ issued final permits on December 22, 2017 and August 22, 2018 for Muskogee Power Plant and Seminole Power Plant, respectively, in compliance with the final 316(b) rule, and OG&E did not incur any material costs associated with the rule's implementation at either location. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation at other facilities following the future issuance of permits from the State of Oklahoma.

In 2015, the EPA issued a final rule addressing the effluent limitation guidelines for power plants under the Federal Clean Water Act. The final rule establishes technology- and performance-based standards that may apply to discharges of six waste streams including bottom ash transport water. Compliance with this rule will occur by 2023; however, on April 12, 2017, the EPA granted a Petition for Reconsideration of the 2015 Rule. On October 13, 2020, the EPA published a final rule to revise the technology-based effluent limitations for flue gas desulfurization waste water and bottom ash transport water. OG&E is evaluating what, if any, compliance actions are needed but is not able to quantify with any certainty what costs may be incurred. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation following issuance of the permits from the State of Oklahoma.

On April 21, 2020, the EPA and U.S. Army Corps of Engineers published a rule to define the scope of federal jurisdiction over wetlands. This final rule replaces the repealed definition of waters of the U.S. from 2015. The rule became effective on June 22, 2020, and OG&E does not expect any material impacts as a result.

Since the purchase of the Redbud facility in 2008, OG&E's average use of treated municipal effluent for all of the needed cooling water at Redbud and McClain is approximately 2.5 billion gallons per year. This use of treated municipal effluent offsets the need for fresh water as cooling water, making fresh water available for other beneficial uses like drinking water, irrigation and recreation.

Site Remediation

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regard to the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Because OG&E utilizes various products and generates wastes that are considered hazardous substances for purposes of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, OG&E could be subject to liability for the costs of cleaning up and restoring sites where those substances have been released to the environment. At this time, it is not anticipated that any associated liability will cause a significant impact to OG&E.

For further discussion regarding contingencies relating to environmental laws and regulations, see Note 15 within "Item 8. Financial Statements and Supplementary Data."



71

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
 
Market risks are, in most cases, risks that are actively traded in a marketplace and have been well studied in regards to quantification. Market risks include, but are not limited to, changes in interest rates and commodity prices. The Registrants' exposure to changes in interest rates relates primarily to short-term variable-rate debt and commercial paper. The Registrants are exposed to commodity prices in their operations to the extent any fuel price changes are not recovered in customer rates and, for OGE Energy, through its equity investment in Enable.
 
Risk Oversight Committee

Management monitors market risks using a risk committee structure. OGE Energy's Risk Oversight Committee, which consists primarily of corporate officers, is responsible for the overall development, implementation and enforcement of strategies and policies for all market risk management activities of the Registrants. This committee's emphasis is a holistic perspective of risk measurement and policies targeting the Registrants' overall financial performance. On a quarterly basis, the Risk Oversight Committee reports to the Audit Committee of OGE Energy's Board of Directors on OGE Energy's risk profile affecting anticipated financial results, including any significant risk issues.
 
OGE Energy also has a Corporate Risk Management function which, in conjunction with the aforementioned committees, is responsible for establishing and enforcing the Registrants' risk policies.
 
Risk Policies
 
Management utilizes risk policies to control the amount of market risk exposure. These policies are designed to provide the Audit Committee of OGE Energy's Board of Directors and senior executives of the Registrants with confidence that the risks taken on by the Registrants' business activities are in accordance with their expectations for financial returns and that the approved policies and controls related to market risk management are being followed.

 Interest Rate Risk

The Registrants' exposure to changes in interest rates primarily relates to variable-rate debt and commercial paper. The Registrants manage their interest rate exposure by monitoring and limiting the effects of market changes in interest rates. The Registrants may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce the effects of these changes. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio, but the Registrants have no intent at this time to utilize interest rate derivatives.

The fair value of OG&E's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities or by calculating the net present value of the monthly payments discounted by OG&E's current borrowing rate. The following table presents OG&E's long-term debt maturities and the weighted-average interest rates by maturity date. OGE Energy currently has no long-term debt outstanding.
Year Ended December 31
(Dollars in millions)
2021 2022 2023 2024 2025 Thereafter Total 12/31/20 Fair Value
Fixed-rate debt (A):
Principal amount $ —  $ —  $ —  $ —  $ —  $ 3,394.4  $ 3,394.4  $ 4,192.8 
Weighted-average interest rate —  % —  % —  % —  % —  % 4.48  % 4.48  %
Variable-rate debt (B):
Principal amount $ —  $ —  $ —  $ —  $ 79.4  $ 56.0  $ 135.4  $ 135.4 
Weighted-average interest rate —  % —  % —  % —  % 0.30  % 0.28  % 0.29  %
(A)Prior to or when these debt obligations mature, OG&E may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.
(B)A hypothetical change of 100 basis points in the underlying variable interest rate incurred by OG&E would change interest expense by $1.4 million annually.


72

Item 8. Financial Statements and Supplementary Data.

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME

Year Ended December 31 (In millions except per share data)
2020 2019 2018
OPERATING REVENUES
Revenues from contracts with customers $ 2,069.8  $ 2,175.5  $ 2,211.7 
Other revenues 52.5  56.1  58.6 
Operating revenues 2,122.3  2,231.6  2,270.3 
COST OF SALES 644.6  786.9  892.5 
OPERATING EXPENSES      
Other operation and maintenance 462.8  491.8  474.6 
Depreciation and amortization 391.3  355.0  321.6 
Taxes other than income 101.4  93.6  92.0 
Operating expenses 955.5  940.4  888.2 
OPERATING INCOME 522.2  504.3  489.6 
OTHER INCOME (EXPENSE)      
Equity in earnings (losses) of unconsolidated affiliates (668.0) 113.9  152.8 
Allowance for equity funds used during construction 4.8  4.5  23.8 
Other net periodic benefit expense (3.9) (9.8) (10.8)
Other income 37.5  21.9  21.7 
Other expense (35.2) (23.5) (23.4)
Net other income (expense) (664.8) 107.0  164.1 
INTEREST EXPENSE      
Interest on long-term debt 152.8  138.3  157.4 
Allowance for borrowed funds used during construction (1.9) (2.8) (11.7)
Interest on short-term debt and other interest charges 7.6  12.4  10.3 
Interest expense 158.5  147.9  156.0 
INCOME (LOSS) BEFORE TAXES (301.1) 463.4  497.7 
INCOME TAX EXPENSE (BENEFIT) (127.4) 29.8  72.2 
NET INCOME (LOSS) $ (173.7) $ 433.6  $ 425.5 
BASIC AVERAGE COMMON SHARES OUTSTANDING 200.1  200.1  199.7 
DILUTED AVERAGE COMMON SHARES OUTSTANDING 200.1  200.7  200.5 
BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE $ (0.87) $ 2.17  $ 2.13 
DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE $ (0.87) $ 2.16  $ 2.12 















The accompanying Combined Notes to Financial Statements are an integral part hereof.


73

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31 (In millions)
2020 2019 2018
Net income (loss) $ (173.7) $ 433.6  $ 425.5 
Other comprehensive income (loss), net of tax:      
Pension Plan and Restoration of Retirement Income Plan:      
Amortization of deferred net loss, net of tax of $1.2, $1.1 and $1.1, respectively
3.9  3.4  3.3 
Net loss arising during the period, net of tax of ($1.7), ($2.6) and ($4.7), respectively
(5.1) (8.3) (14.1)
Settlement cost, net of tax of $0.7, $2.7 and $1.6, respectively
2.2  8.6  4.7 
Postretirement benefit plans:      
Amortization of prior service credit, net of tax of ($0.6), ($0.6) and ($0.6), respectively
(1.7) (1.7) (1.7)
Amortization of deferred net gain, net of tax of $0.0, $0.0 and $0.0, respectively
(0.1) (0.2) — 
Net gain (loss) arising during the period, net of tax of ($0.8), ($0.1) and $0.7, respectively
(2.4) (0.2) 2.1 
Curtailment cost, net of tax of ($0.1), $0.0 and $0.0, respectively
(0.3) —  — 
Other comprehensive loss from unconsolidated affiliates, net of tax ($0.2), ($0.2) and $0.0, respectively
(0.7) (0.6) — 
Other comprehensive income (loss), net of tax (4.2) 1.0  (5.7)
Comprehensive income (loss) $ (177.9) $ 434.6  $ 419.8 




























The accompanying Combined Notes to Financial Statements are an integral part hereof.


74

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31 (In millions)
2020 2019 2018
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income (loss) $ (173.7) $ 433.6  $ 425.5 
Adjustments to reconcile net income (loss) to net cash provided from operating activities:  
Depreciation and amortization 391.3  355.0  321.6 
Deferred income taxes and investment tax credits, net (134.5) 27.6  78.5 
Equity in (earnings) losses of unconsolidated affiliates 668.0  (113.9) (152.8)
Distributions from unconsolidated affiliates 91.7  125.5  141.2 
Allowance for equity funds used during construction (4.8) (4.5) (23.8)
Stock-based compensation expense 9.8  13.9  13.4 
Regulatory assets (112.0) (47.1) (10.8)
Regulatory liabilities (64.0) (45.6) (16.5)
Other assets (9.2) (3.8) 6.2 
Other liabilities (26.3) 19.2  1.0 
Change in certain current assets and liabilities:    
Accounts receivable and accrued unbilled revenues, net 3.1  18.8  19.8 
Income taxes receivable 2.8  (1.0) (4.1)
Fuel, materials and supplies inventories (8.9) 4.2  27.3 
Fuel recoveries 63.3  (33.0) (3.4)
Other current assets (16.8) 5.1  25.1 
Accounts payable 59.8  (34.5) 29.7 
Other current liabilities (26.8) (38.0) 73.2 
Net cash provided from operating activities 712.8  681.5  951.1 
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (less allowance for equity funds used during construction) (650.5) (635.5) (573.6)
Investment in unconsolidated affiliates (4.4) (7.7) (2.5)
Return of capital - unconsolidated affiliates —  18.5  — 
Proceeds from sale of assets —  —  0.1 
Net cash used in investing activities (654.9) (624.7) (576.0)
CASH FLOWS FROM FINANCING ACTIVITIES    
Increase (decrease) in short-term debt (17.0) 112.0  (168.4)
Proceeds from long-term debt 297.1  296.5  396.0 
Payment of long-term debt (0.1) (250.1) (250.1)
Dividends paid on common stock (314.9) (299.2) (272.2)
Cash paid for employee equity-based compensation and expense of common stock (7.1) (10.3) (0.5)
Purchase of treasury stock (14.7) —  — 
Other (0.1) —  — 
Net cash used in financing activities (56.8) (151.1) (295.2)
NET CHANGE IN CASH AND CASH EQUIVALENTS 1.1  (94.3) 79.9 
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR —  94.3  14.4 
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 1.1  $ —  $ 94.3 
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of interest capitalized of $1.9, $2.8 and $11.7, respectively)
$ 153.4  $ 152.2  $ 153.8 
Income taxes (net of income tax refunds) $ 3.9  $ 5.5  $ 2.8 
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement $ 6.8  $ 28.9  $ (9.2)
The accompanying Combined Notes to Financial Statements are an integral part hereof.


75

OGE ENERGY CORP.
CONSOLIDATED BALANCE SHEETS

December 31 (In millions)
2020 2019
ASSETS    
CURRENT ASSETS    
Cash and cash equivalents $ 1.1  $ — 
Accounts receivable, less reserve of $2.6 and $1.5, respectively
157.8  153.8 
Accrued unbilled revenues 67.6  64.7 
Income taxes receivable 8.1  10.9 
Fuel inventories 36.5  46.3 
Materials and supplies, at average cost 116.2  90.6 
Fuel clause under recoveries —  39.5 
Other 41.2  24.4 
Total current assets 428.5  430.2 
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates 397.4  1,151.5 
Other 86.7  82.7 
Total other property and investments 484.1  1,234.2 
PROPERTY, PLANT AND EQUIPMENT    
In service 13,296.7  12,771.1 
Construction work in progress 145.5  141.6 
Total property, plant and equipment 13,442.2  12,912.7 
Less: accumulated depreciation 4,067.6  3,868.1 
Net property, plant and equipment 9,374.6  9,044.6 
DEFERRED CHARGES AND OTHER ASSETS    
Regulatory assets 415.6  306.0 
Other 16.0  9.3 
Total deferred charges and other assets 431.6  315.3 
TOTAL ASSETS $ 10,718.8  $ 11,024.3 

























The accompanying Combined Notes to Financial Statements are an integral part hereof.


76

OGE ENERGY CORP.
CONSOLIDATED BALANCE SHEETS (Continued)

December 31 (In millions)
2020 2019
LIABILITIES AND STOCKHOLDERS' EQUITY    
CURRENT LIABILITIES    
Short-term debt $ 95.0  $ 112.0 
Accounts payable 251.5  194.9 
Dividends payable 80.5  77.6 
Customer deposits 81.1  83.0 
Accrued taxes 55.7  41.9 
Accrued interest 40.2  37.9 
Accrued compensation 31.1  40.6 
Fuel clause over recoveries 28.6  4.8 
Other 33.7  65.2 
Total current liabilities 697.4  657.9 
LONG-TERM DEBT 3,494.4  3,195.2 
DEFERRED CREDITS AND OTHER LIABILITIES    
Accrued benefit obligations 231.4  225.0 
Deferred income taxes 1,268.6  1,375.8 
Deferred investment tax credits 10.9  7.1 
Regulatory liabilities 1,188.9  1,223.5 
Other 195.4  200.3 
Total deferred credits and other liabilities 2,895.2  3,031.7 
Total liabilities 7,087.0  6,884.8 
COMMITMENTS AND CONTINGENCIES (NOTE 15)
STOCKHOLDERS' EQUITY    
Common stockholders' equity 1,124.6  1,131.3 
Retained earnings 2,544.6  3,036.1 
Accumulated other comprehensive loss, net of tax (32.1) (27.9)
Treasury stock, at cost (5.3) — 
Total stockholders' equity 3,631.8  4,139.5 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 10,718.8  $ 11,024.3 






















The accompanying Combined Notes to Financial Statements are an integral part hereof.


77

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31 (In millions except per share data)
2020 2019
STOCKHOLDERS' EQUITY
Common stock, par value $0.01 per share; authorized 450.0 shares; and outstanding 200.1 shares and 200.1 shares, respectively
$ 2.0  $ 2.0 
Premium on common stock 1,122.6  $ 1,129.3 
Retained earnings 2,544.6  3,036.1 
Accumulated other comprehensive loss, net of tax (32.1) (27.9)
Treasury stock, at cost, 0.1 and 0.0 shares, respectively
(5.3) — 
Total stockholders' equity 3,631.8  4,139.5 
LONG-TERM DEBT
SERIES DUE DATE
Senior Notes - OG&E
6.65%
Senior Notes, Series Due July 15, 2027
125.0  125.0 
6.50%
Senior Notes, Series Due April 15, 2028
100.0  100.0 
3.80%
Senior Notes, Series Due August 15, 2028
400.0  400.0 
3.30%
Senior Notes, Series Due March 15, 2030
300.0  300.0 
3.25%
Senior Notes, Series Due April 1, 2030
300.0  — 
5.75%
Senior Notes, Series Due January 15, 2036
110.0  110.0 
6.45%
Senior Notes, Series Due February 1, 2038
200.0  200.0 
5.85%
Senior Notes, Series Due June 1, 2040
250.0  250.0 
5.25%
Senior Notes, Series Due May 15, 2041
250.0  250.0 
3.90%
Senior Notes, Series Due May 1, 2043
250.0  250.0 
4.55%
Senior Notes, Series Due March 15, 2044
250.0  250.0 
4.00%
Senior Notes, Series Due December 15, 2044
250.0  250.0 
4.15%
Senior Notes, Series Due April 1, 2047
300.0  300.0 
3.85%
Senior Notes, Series Due August 15, 2047
300.0  300.0 
3.80%
Tinker Debt, Due August 31, 2062
9.4  9.5 
Other Bonds - OG&E
0.28% - 5.35%
Garfield Industrial Authority, January 1, 2025
47.0  47.0 
0.33% - 4.31%
Muskogee Industrial Authority, January 1, 2025
32.4  32.4 
0.28% - 5.35%
Muskogee Industrial Authority, June 1, 2027
56.0  56.0 
Unamortized debt expense (25.3) (24.2)
Unamortized discount (10.1) (10.5)
Total long-term debt 3,494.4  3,195.2 
Less: long-term debt due within one year —  — 
Total long-term debt (excluding long-term debt due within one year) 3,494.4  3,195.2 
Total capitalization (including long-term debt due within one year) $ 7,126.2  $ 7,334.7 







The accompanying Combined Notes to Financial Statements are an integral part hereof.


78

OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Common Stock Treasury Stock



(In millions) 		Shares Value Shares Value Premium on Common Stock Retained Earnings Accumulated Other Comprehensive (Loss) Income Total
Balance at December 31, 2017 199.7  $ 2.0  —  $ —  $ 1,112.8  $ 2,759.5  $ (23.2) $ 3,851.1 
Net income —  —  —  —  —  425.5  —  425.5 
Other comprehensive loss, net of tax —  —  —  —  —  —  (5.7) (5.7)
Dividends declared on common stock ($1.3950 per share)
—  —  —  —  —  (278.7) —  (278.7)
Expense of common stock —  —  —  —  (0.1) —  —  (0.1)
Stock-based compensation —  —  —  —  13.0  —  —  13.0 
Balance at December 31, 2018 199.7  $ 2.0  —  $ —  $ 1,125.7  $ 2,906.3  $ (28.9) $ 4,005.1 
Net income —  —  —  —  —  433.6  —  433.6 
Other comprehensive income, net of tax —  —  —  —  —  —  1.0  1.0 
Dividends declared on common stock ($1.5050 per share)
—  —  —  —  —  (303.8) —  (303.8)
Stock-based compensation 0.4  —  —  —  3.6  —  —  3.6 
Balance at December 31, 2019 200.1  $ 2.0  —  $ —  $ 1,129.3  $ 3,036.1  $ (27.9) $ 4,139.5 
Net loss —  —  —  —  —  (173.7) —  (173.7)
Other comprehensive loss, net of tax —  —  —  —  —  —  (4.2) (4.2)
Dividends declared on common stock ($1.5800 per share)
—  —  —  —  —  (317.8) —  (317.8)
Purchase of treasury stock —  —  0.4 (14.7) —  —  —  (14.7)
Stock-based compensation —  —  (0.3) 9.4  (6.7) —  —  2.7 
Balance at December 31, 2020 200.1  $ 2.0  0.1  $ (5.3) $ 1,122.6  $ 2,544.6  $ (32.1) $ 3,631.8 




































The accompanying Combined Notes to Financial Statements are an integral part hereof.


79

OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME

Year Ended December 31 (In millions)
2020 2019 2018
OPERATING REVENUES
Revenues from contracts with customers $ 2,069.8  $ 2,175.5  $ 2,211.7 
Other revenues 52.5  56.1  58.6 
Operating revenues 2,122.3  2,231.6  2,270.3 
COST OF SALES 644.6  786.9  892.5 
OPERATING EXPENSES    
Other operation and maintenance 464.4  492.5  473.8 
Depreciation and amortization 391.3  355.0  321.6 
Taxes other than income 97.2  89.5  88.2 
Operating expenses 952.9  937.0  883.6 
OPERATING INCOME 524.8  507.7  494.2 
OTHER INCOME (EXPENSE)    
Allowance for equity funds used during construction 4.8  4.5  23.8 
Other net periodic benefit expense (3.1) (1.2) (8.9)
Other income 5.0  6.7  14.1 
Other expense (2.6) (6.9) (3.4)
Net other income 4.1  3.1  25.6 
INTEREST EXPENSE    
Interest on long-term debt 152.8  138.3  157.4 
Allowance for borrowed funds used during construction (1.9) (2.8) (11.7)
Interest on short-term debt and other interest charges 3.9  5.0  6.1 
Interest expense 154.8  140.5  151.8 
INCOME BEFORE TAXES 374.1  370.3  368.0 
INCOME TAX EXPENSE 34.7  20.1  40.0 
NET INCOME 339.4  350.2  328.0 
Other comprehensive income, net of tax —  —  — 
COMPREHENSIVE INCOME $ 339.4  $ 350.2  $ 328.0 























The accompanying Combined Notes to Financial Statements are an integral part hereof.



80

OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS

Year Ended December 31 (In millions)
2020 2019 2018
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income $ 339.4  $ 350.2  $ 328.0 
Adjustments to reconcile net income to net cash provided from operating activities:    
Depreciation and amortization 391.3  355.0  321.6 
Deferred income taxes and investment tax credits, net 40.9  20.4  56.6 
Allowance for equity funds used during construction (4.8) (4.5) (23.8)
Stock-based compensation expense 3.0  4.9  4.6 
Regulatory assets (112.0) (47.1) (10.8)
Regulatory liabilities (64.0) (45.6) (16.5)
Other assets (3.4) 3.8  1.9 
Other liabilities (24.3) 8.4  — 
Change in certain current assets and liabilities:    
Accounts receivable and accrued unbilled revenues, net 4.5  17.0  19.5 
Fuel, materials and supplies inventories (8.9) 4.2  27.3 
Fuel recoveries 63.3  (33.0) (3.4)
Other current assets (17.3) 5.9  23.1 
Accounts payable 64.8  (30.0) 19.0 
Income taxes payable - parent (5.3) (0.7) (15.6)
Other current liabilities (26.8) (35.1) 72.5 
Net cash provided from operating activities 640.4  573.8  804.0 
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (less allowance for equity funds used during construction) (650.5) (635.5) (573.6)
Proceeds from sale of assets —  —  0.1 
Net cash used in investing activities (650.5) (635.5) (573.5)
CASH FLOWS FROM FINANCING ACTIVITIES    
Proceeds from long-term debt 297.1  296.5  396.0 
Payment of long-term debt (0.1) (250.1) (250.1)
Dividends paid on common stock (325.0) —  (185.0)
Changes in advances with parent 38.1  15.3  (191.4)
Net cash provided from (used in) financing activities 10.1  61.7  (230.5)
NET CHANGE IN CASH AND CASH EQUIVALENTS —  —  — 
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR —  —  — 
CASH AND CASH EQUIVALENTS AT END OF YEAR $ —  $ —  $ — 
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of interest capitalized of $1.9, $2.8 and $11.7, respectively)
$ 150.2  $ 144.6  $ 149.7 
Income taxes (net of income tax refunds) $ (0.2) $ 1.3  $ 0.9 
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement $ 6.8  $ 28.9  $ (9.2)










The accompanying Combined Notes to Financial Statements are an integral part hereof.



81

OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS

December 31 (In millions)
2020 2019
ASSETS    
CURRENT ASSETS    
Accounts receivable, less reserve of $2.6 and $1.5, respectively
$ 156.3  $ 153.8 
Accrued unbilled revenues 67.7  64.7 
Advances to parent 272.0  304.8 
Fuel inventories 36.5  46.3 
Materials and supplies, at average cost 116.2  90.6 
Fuel clause under recoveries —  39.5 
Other 36.9  19.6 
Total current assets 685.6  719.3 
OTHER PROPERTY AND INVESTMENTS 4.1  4.7 
PROPERTY, PLANT AND EQUIPMENT    
In service 13,290.6  12,765.0 
Construction work in progress 145.5  141.6 
Total property, plant and equipment 13,436.1  12,906.6 
Less: accumulated depreciation 4,067.6  3,868.1 
Net property, plant and equipment 9,368.5  9,038.5 
DEFERRED CHARGES AND OTHER ASSETS    
Regulatory assets 415.6  306.0 
Other 15.2  8.1 
Total deferred charges and other assets 430.8  314.1 
TOTAL ASSETS $ 10,489.0  $ 10,076.6 










 
 
















The accompanying Combined Notes to Financial Statements are an integral part hereof.


82

OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS (Continued)

December 31 (In millions)
2020 2019
LIABILITIES AND STOCKHOLDER'S EQUITY    
CURRENT LIABILITIES    
Accounts payable $ 236.7  $ 175.0 
Customer deposits 81.1  83.0 
Accrued taxes 53.3  41.9 
Accrued interest 40.2  37.9 
Accrued compensation 22.5  29.5 
Fuel clause over recoveries 28.6  4.8 
Other 33.5  65.1 
Total current liabilities 495.9  437.2 
LONG-TERM DEBT 3,494.4  3,195.2 
DEFERRED CREDITS AND OTHER LIABILITIES    
Accrued benefit obligations 135.4  133.3 
Deferred income taxes 1,020.8  951.4 
Deferred investment tax credits 10.9  7.1 
Regulatory liabilities 1,188.9  1,223.5 
Other 167.1  170.6 
Total deferred credits and other liabilities 2,523.1  2,485.9 
Total liabilities 6,513.4  6,118.3 
COMMITMENTS AND CONTINGENCIES (NOTE 15)
STOCKHOLDER'S EQUITY    
Common stockholder's equity 1,039.5  1,036.6 
Retained earnings 2,936.1  2,921.7 
Total stockholder's equity 3,975.6  3,958.3 
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 10,489.0  $ 10,076.6 


























The accompanying Combined Notes to Financial Statements are an integral part hereof.


83

OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION

December 31 (In millions except per share data)
2020 2019
STOCKHOLDER'S EQUITY
Common stock, par value $2.50 per share; authorized 100.0 shares; and outstanding 40.4 shares and 40.4 shares, respectively
$ 100.9  $ 100.9 
Premium on common stock 938.6  935.7 
Retained earnings 2,936.1  2,921.7 
Total stockholder's equity 3,975.6  3,958.3 
LONG-TERM DEBT
SERIES DUE DATE
Senior Notes
6.65%
Senior Notes, Series Due July 15, 2027
125.0  125.0 
6.50%
Senior Notes, Series Due April 15, 2028
100.0  100.0 
3.80%
Senior Notes, Series Due August 15, 2028
400.0  400.0 
3.30%
Senior Notes, Series Due March 15, 2030
300.0  300.0 
3.25%
Senior Notes, Series Due April 1, 2030
300.0  — 
5.75%
Senior Notes, Series Due January 15, 2036
110.0  110.0 
6.45%
Senior Notes, Series Due February 1, 2038
200.0  200.0 
5.85%
Senior Notes, Series Due June 1, 2040
250.0  250.0 
5.25%
Senior Notes, Series Due May 15, 2041
250.0  250.0 
3.90%
Senior Notes, Series Due May 1, 2043
250.0  250.0 
4.55%
Senior Notes, Series Due March 15, 2044
250.0  250.0 
4.00%
Senior Notes, Series Due December 15, 2044
250.0  250.0 
4.15%
Senior Notes, Series Due April 1, 2047
300.0  300.0 
3.85%
Senior Notes, Series Due August 15, 2047
300.0  300.0 
3.80%
Tinker Debt, Due August 31, 2062
9.4  9.5 
Other Bonds
0.28% - 5.35%
Garfield Industrial Authority, January 1, 2025
47.0  47.0 
0.33% - 4.31%
Muskogee Industrial Authority, January 1, 2025
32.4  32.4 
0.28% - 5.35%
Muskogee Industrial Authority, June 1, 2027
56.0  56.0 
Unamortized debt expense (25.3) (24.2)
Unamortized discount (10.1) (10.5)
Total long-term debt 3,494.4  3,195.2 
Less: long-term debt due within one year —  — 
Total long-term debt (excluding long-term debt due within one year) 3,494.4  3,195.2 
Total capitalization (including long-term debt due within one year) $ 7,470.0  $ 7,153.5 








The accompanying Combined Notes to Financial Statements are an integral part hereof.


84

OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
(In millions) Shares Outstanding Common Stock Premium on Common Stock Retained Earnings Total
Balance at December 31, 2017 40.4  $ 100.9  $ 926.3  $ 2,428.5  $ 3,455.7 
Net income —  —  —  328.0  328.0 
Dividends declared on common stock —  —  —  (185.0) (185.0)
Stock-based compensation —  —  4.6  —  4.6 
Balance at December 31, 2018 40.4  $ 100.9  $ 930.9  $ 2,571.5  $ 3,603.3 
Net income — —  —  350.2  350.2 
Stock-based compensation — —  4.8  —  4.8 
Balance at December 31, 2019 40.4  $ 100.9  $ 935.7  $ 2,921.7  $ 3,958.3 
Net income —  —  —  339.4  339.4 
Dividends declared on common stock —  —  —  (325.0) (325.0)
Stock-based compensation —  —  2.9  —  2.9 
Balance at December 31, 2020 40.4  $ 100.9  $ 938.6  $ 2,936.1  $ 3,975.6 





































The accompanying Combined Notes to Financial Statements are an integral part hereof.


85

COMBINED NOTES TO FINANCIAL STATEMENTS

Index of Combined Notes to Financial Statements

The Combined Notes to the Financial Statements are a combined presentation for OGE Energy and OG&E. The following table indicates the Registrant(s) to which each Note applies.
OGE Energy OG&E
Note 1. Summary of Significant Accounting Policies X X
Note 2. Accounting Pronouncements X X
Note 3. Revenue Recognition X X
Note 4. Leases X X
Note 5. Investment in Unconsolidated Affiliates X
Note 6. Related Party Transactions X X
Note 7. Fair Value Measurements X X
Note 8. Stock-Based Compensation X X
Note 9. Income Taxes X X
Note 10. Common Equity X X
Note 11. Long-Term Debt X X
Note 12. Short-Term Debt and Credit Facilities X X
Note 13. Retirement Plans and Postretirement Benefit Plans X X
Note 14. Report of Business Segments X
Note 15. Commitments and Contingencies X X
Note 16. Rate Matters and Regulation X X

1.Summary of Significant Accounting Policies

Organization

OGE Energy is a holding company with investments in energy and energy services providers offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S. OGE Energy conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of OGE Energy and its wholly-owned subsidiaries, including OG&E, are included in OGE Energy's consolidated financial statements. All intercompany transactions and balances are eliminated in such consolidation. OGE Energy generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance.

OG&E. OGE Energy's electric utility operations are conducted through OG&E, which generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. OG&E's rates are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is a wholly-owned subsidiary of OGE Energy. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

Enable. OGE Energy's natural gas midstream operations segment represents OGE Energy's investment in Enable. The investment in Enable is held through wholly-owned subsidiaries and ultimately OGE Holdings. Enable is primarily engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns crude oil gathering assets in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama. Enable's general partner is equally controlled by OGE Energy and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, OGE Energy accounts for its interest in Enable using the equity


86

method of accounting. In February 2021, Enable entered into a definitive merger agreement with Energy Transfer. For further discussion, see Note 5.

OGE Energy charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and Enable are assigned as such. Operating costs incurred for the benefit of OG&E and Enable are allocated either as overhead based primarily on labor costs or using the "Distrigas" method. The "Distrigas" method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. OGE Energy adopted this method as a result of a recommendation by the OCC Staff. OGE Energy believes this method provides a reasonable basis for allocating common expenses.

Accounting Records

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.

OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates.



87

The following table presents a summary of OG&E's regulatory assets and liabilities.
December 31 (In millions)
2020 2019
REGULATORY ASSETS    
Current:    
SPP cost tracker under recovery (A) $ 7.0  $ — 
Generation Capacity Replacement rider under recovery (A) 4.4  3.7 
Fuel clause under recoveries —  39.5 
Other (A) 8.4  5.5 
Total current regulatory assets $ 19.8  $ 48.7 
Non-current:
Benefit obligations regulatory asset $ 164.9  $ 167.2 
Deferred storm expenses 158.8  65.5 
Sooner Dry Scrubbers 19.7  20.6 
Pension tracker 18.1  2.3 
Smart Grid 11.2  18.4 
Unamortized loss on reacquired debt 9.7  10.6 
Arkansas deferred pension expenses 9.3  8.0 
Frontier Plant deferred expenses 6.4  — 
COVID-19 impacts 6.4  — 
Other 11.1  13.4 
Total non-current regulatory assets $ 415.6  $ 306.0 
REGULATORY LIABILITIES
Current:
Fuel clause over recoveries $ 28.6  $ 4.8 
Oklahoma demand program rider over recovery (B) 1.5  2.0 
Reserve for tax refund and interim surcharge (B) 0.8  12.7 
SPP cost tracker over recovery (B) —  2.6 
Other (B) 4.2  6.9 
Total current regulatory liabilities $ 35.1  $ 29.0 
Non-current:
Income taxes refundable to customers, net $ 867.4  $ 899.2 
Accrued removal obligations, net 316.8  318.5 
Other 4.7  5.8 
Total non-current regulatory liabilities $ 1,188.9  $ 1,223.5 
(A)Included in Other Current Assets in the balance sheets.
(B)Included in Other Current Liabilities in the balance sheets.

OG&E recovers certain SPP costs related to base plan charges from its customers and refunds certain SPP revenues received to its customers in Oklahoma through the SPP cost tracker and in Arkansas through the transmission cost recovery rider.

OG&E recovers the Oklahoma jurisdictional portion of costs, including non-fuel operation and maintenance expenses, depreciation, taxes other than income taxes and a return on capital, for its investment in the River Valley plant through the Generation Capacity Replacement Rider. The OCC also authorized OG&E to defer the same costs related to its investment in the Frontier plant to a regulatory asset, and recovery of these costs will be considered in future rate proceedings.

Fuel clause under and over recoveries are generated from OG&E's customers when OG&E's cost of fuel either exceeds or is less than the amount billed to its customers, respectively. OG&E's fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E under recovers fuel costs in periods of rising fuel prices above the


88

baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances.

The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss and prior service cost. These expenses are recorded as a regulatory asset as OG&E historically has recovered and currently recovers pension and postretirement benefit plan expense in its electric rates. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the benefit obligations regulatory asset balance to be reclassified to accumulated other comprehensive income.

The following table presents a summary of the components of the benefit obligations regulatory asset.
December 31 (In millions)
2020 2019
Pension Plan and Restoration of Retirement Income Plan:
Net loss $ 147.3  $ 160.5 
Postretirement Benefit Plans:  
Net loss 26.2  23.3 
Prior service cost (8.6) (16.6)
Total $ 164.9  $ 167.2 
 
OG&E includes in expense any Oklahoma storm-related operation and maintenance expenses up to $2.7 million annually and defers to a regulatory asset any additional expenses incurred over $2.7 million. OG&E expects to recover the amounts deferred each year over a five-year period in accordance with historical practice.

As approved by the OCC, OG&E deferred the non-fuel incremental operation and maintenance expenses, depreciation, debt cost associated with the capital investment and related ad valorem taxes for the Dry Scrubbers at Sooner Units 1 and 2 as a regulatory asset, and these costs are being recovered over 25 years.

OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate reviews. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker regulatory asset in the table above.

OG&E deferred to a regulatory asset the incremental and stranded costs that were accumulated during Smart Grid deployment, including (i) costs for web portal access, (ii) costs for education and home energy reports and (iii) stranded costs associated with OG&E's analog electric meters, which have been replaced by smart meters. As approved by the OCC and APSC, these costs are being recovered over a six-year period ending in 2022 in Oklahoma and 2023 in Arkansas.

Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the early retirement of OG&E's long-term debt. These amounts are recorded in interest expense and are being amortized over the term of the long-term debt which replaced the previous long-term debt. The unamortized loss on reacquired debt is recovered as a part of OG&E's cost of capital.

Arkansas includes a certain level of pension expense in base rates. When the Pension Plan experiences a settlement, which represents an acceleration of future pension costs, OG&E defers to a regulatory asset the Arkansas jurisdictional portion of each settlement, which historically has been recovered from customers over the average life of the remaining plan participants. A portion of these settlements is being recovered in current rates, and recovery of additional amounts will be requested as additional settlements occur. For additional information related to settlements, see Note 13.

In response to the COVID-19 pandemic, the OCC and APSC issued orders allowing OG&E to defer certain expenses related to its COVID-19 response. For additional information about these orders, see Note 16 and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Recent Developments."

OG&E recovers program costs related to the Demand and Energy Efficiency Program in Oklahoma through the Demand Program Rider, which operates on a three-year program cycle. The current program cycle, which runs through 2021, includes recovery of (i) energy efficiency program costs, (ii) lost revenues associated with certain achieved energy efficiency and demand savings, (iii) performance-based incentives and (iv) costs associated with research and development investments.


89

As a result of filings with the OCC, APSC and FERC, OG&E established mechanisms to refund to customers the amount of excess taxes received through rates, with an ongoing adjustment for any excess accumulated deferred income taxes resulting from the Tax Cuts and Jobs Act of 2017. Additional amounts due to customers will be refunded in accordance with agreements in each jurisdiction.

Income taxes refundable to customers, net, represents the reduction in accumulated deferred income taxes resulting from the reduction in the federal income tax rate as part of the Tax Cuts and Jobs Act of 2017 and includes income taxes recoverable from customers that represent income tax benefits previously used to reduce OG&E's revenues (treated as regulatory assets). These liabilities will be returned to customers in varying amounts over approximately 80 years, and the assets will be amortized over the estimated remaining life of the assets to which they relate, as the temporary differences that generated the income tax benefits turn around.

Accrued removal obligations, net represents asset retirement costs previously recovered from ratepayers for other than legal obligations.
Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets or liabilities, which could have significant financial effects.
Use of Estimates
 
In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Changes to these assumptions and estimates could have a material effect on the Registrants' financial statements. However, the Registrants believe they have taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the Registrants that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas where the most significant judgment is exercised include the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations, regulatory assets and liabilities, unbilled revenues and the allowance for uncollectible accounts receivable. For OGE Energy, significant judgment is also exercised in the determination of any impairment of equity method investments.

Cash and Cash Equivalents
 
For purposes of the financial statements, the Registrants consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.

Allowance for Uncollectible Accounts Receivable
 
Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is generally calculated by multiplying the last six months of electric revenue by the provision rate, which is based on a 12-month historical average of actual balances written off and is adjusted for current conditions and supportable forecasts as necessary. To the extent the historical collection rates, when incorporating forecasted conditions, are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized, such as in response to COVID-19 impacts. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable in the balance sheets and is included in Other Operation and Maintenance Expense in the statements of income. The allowance for uncollectible accounts receivable was $2.6 million and $1.5 million at December 31, 2020 and 2019, respectively.
 
New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers whose outside credit scores indicate an elevated risk are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored, and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.



90

The Registrants considered COVID-19 pandemic impacts when calculating their reserve on accounts receivable as of December 31, 2020, as further discussed within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Recent Developments."

Fuel Inventories

Fuel inventories for the generation of electricity consist of coal, natural gas and oil. OG&E uses the weighted-average cost method of accounting for inventory that is physically added to or withdrawn from storage or stockpiles. The amount of fuel inventory was $36.5 million and $46.3 million at December 31, 2020 and 2019, respectively.
 
Property, Plant and Equipment
  
All property, plant and equipment is recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances, and the cost of such property net of any salvage proceeds is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation, and the remaining balance net of any salvage proceeds is recorded as a loss in the statements of income as Other Expense. Repair and replacement of minor items of property are included in the statements of income as Other Operation and Maintenance Expense.
 
The following tables present OG&E's ownership interest in the jointly-owned McClain Plant and the jointly-owned Redbud Plant, and, as disclosed below, only OG&E's ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in these tables. The owners of the remaining interests in the McClain Plant and the Redbud Plant are responsible for providing their own financing of capital expenditures. Also, only OG&E's proportionate interests of any direct expenses of the McClain Plant and the Redbud Plant, such as fuel, maintenance expense and other operating expenses, are included in the applicable financial statement captions in the statements of income.
December 31, 2020 (In millions)
Percentage Ownership Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment
McClain Plant (A) 77  % $ 257.1  $ 96.0  $ 161.1 
Redbud Plant (A)(B) 51  % $ 531.8  $ 181.9  $ 349.9 
(A)Construction work in progress was $0.1 million and $1.8 million for the McClain and Redbud Plants, respectively.
(B)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $67.3 million.

December 31, 2019 (In millions)
Percentage Ownership Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment
McClain Plant (A) 77  % $ 254.4  $ 83.5  $ 170.9 
Redbud Plant (A)(B) 51  % $ 529.9  $ 159.0  $ 370.9 
(A)Construction work in progress was $0.2 million and $1.4 million for the McClain and Redbud Plants, respectively.
(B)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $61.8 million.


91

 
The following tables present the Registrants' major classes of property, plant and equipment and related accumulated depreciation. 
December 31, 2020 (In millions)
Total Property, Plant and Equipment     Accumulated Depreciation Net Property, Plant and Equipment
OG&E:
Distribution assets $ 4,809.9  $ 1,422.1  $ 3,387.8 
Electric generation assets (A) 4,932.2  1,713.6  3,218.6 
Transmission assets (B) 2,944.6  591.7  2,352.9 
Intangible plant 254.1  153.9  100.2 
Other property and equipment 495.3  186.3  309.0 
OG&E property, plant and equipment 13,436.1  4,067.6  9,368.5 
Non-OG&E property, plant and equipment 6.1  —  6.1 
Total OGE Energy property, plant and equipment $ 13,442.2  $ 4,067.6  $ 9,374.6 
(A)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $67.3 million.
(B)This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.9 million.

December 31, 2019 (In millions)
Total Property, Plant and Equipment     Accumulated Depreciation Net Property, Plant and Equipment
OG&E:
Distribution assets $ 4,468.6  $ 1,381.1  $ 3,087.5 
Electric generation assets (A) 4,838.6  1,601.0  3,237.6 
Transmission assets (B) 2,901.1  565.5  2,335.6 
Intangible plant 225.2  145.4  79.8 
Other property and equipment 473.1  175.1  298.0 
OG&E property, plant and equipment 12,906.6  3,868.1  9,038.5 
Non-OG&E property, plant and equipment 6.1  —  6.1 
Total OGE Energy property, plant and equipment $ 12,912.7  $ 3,868.1  $ 9,044.6 
(A)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $61.8 million.
(B)This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.8 million.

OG&E's unamortized computer software costs, included in intangible plant above, were $89.7 million and $71.3 million at December 31, 2020 and 2019, respectively. OG&E's amortization expense for computer software costs was $14.9 million, $11.0 million and $9.6 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Depreciation and Amortization
  
The provision for depreciation, which was 2.6 percent and 2.7 percent of the average depreciable utility plant for 2020 and 2019, respectively, is calculated using the straight-line method over the estimated service life of the utility assets. Depreciation is provided at the unit level for production plant and at the account or sub-account level for all other plant and is based on the average life group method. In 2021, the provision for depreciation is projected to be 2.6 percent of the average depreciable utility plant.

Amortization of intangible assets is calculated using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2020, 99.0 percent will be amortized over 10.4 years with the remaining 1.0 percent of the intangible plant balance at December 31, 2020 being amortized over 23.7 years.  

Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life of the acquired assets. Plant acquisition adjustments include $148.3 million for the Redbud Plant, which is being amortized over a 27 year life, and $3.3 million for certain transmission substation facilities in OG&E's service territory, which is being amortized over a 37 to 59 year period.


92

 
Investment in Unconsolidated Affiliates

OGE Energy's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, OGE Energy is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable; therefore, OGE Energy accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and OGE Energy's share of the investee's comprehensive income as adjusted for basis differences. OGE Energy's maximum exposure to loss related to Enable is limited to its equity investment in Enable at December 31, 2020 as presented in Note 14. OGE Energy evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. When indicators exist, the fair value is estimated and compared to the investment carrying value, and if any impairment is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value.

OGE Energy determined, effective March 31, 2020, that an other than temporary decline in the value of OGE Energy's investment in Enable had occurred. Further information detailing the results of OGE Energy's impairment analysis and fair value measurement can be found in Notes 5 and 7, respectively.

OGE Energy considers distributions received from Enable which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and are classified as operating activities in the statements of cash flows. OGE Energy considers distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and are classified as investing activities in the statements of cash flows.

Asset Retirement Obligations

OG&E has asset retirement obligations primarily associated with the removal of company-owned wind turbines on leased land, as well as the removal of asbestos from certain power generating stations. OG&E has recorded asset retirement obligations that are being accreted over their respective lives ranging from five to 68 years. Asset retirement obligations are included in Other Deferred Credits in the Registrants' balance sheets. 

The following table presents changes to OG&E's asset retirement obligations during the years ended December 31, 2020 and 2019.
(In millions) 2020 2019
Balance at January 1 $ 73.5  $ 83.9 
Accretion expense 0.5  1.0 
Revisions in estimated cash flows (A) 5.8  (2.4)
Liabilities settled (B) (0.2) (9.0)
Balance at December 31 $ 79.6  $ 73.5 
(A)Assumptions changed related to the estimated timing and estimated cost of the removal of asbestos at OG&E's generating facilities.
(B)Asset retirement obligations were settled for asbestos removal at one of OG&E's generating facilities.

Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised and remediation efforts proceed. For sites where OG&E has been designated as one of several potentially responsible parties, the amount accrued represents OG&E's estimated share of the cost. OG&E had $25.0 million and $18.7 million in accrued environmental liabilities at December 31, 2020 and 2019, respectively, which are included in OG&E's asset retirement obligations.


93

Allowance for Funds Used During Construction
 
Allowance for funds used during construction, a non-cash item, is reflected as an increase to Net Other Income and a reduction to Interest Expense in the statements of income and as an increase to Construction Work in Progress in the balance sheets. Allowance for funds used during construction is calculated according to the FERC requirements for the imputed cost of equity and borrowed funds. Allowance for funds used during construction rates, compounded semi-annually, were 7.3 percent, 7.6 percent and 7.6 percent for the years ended December 31, 2020, 2019 and 2018, respectively.  

Collection of Sales Tax
 
In the normal course of its operations, OG&E collects sales tax from its customers. OG&E records a current liability for sales taxes when it bills its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities. OG&E excludes the sales tax collected from its operating revenues.

Revenue Recognition

General

OG&E recognizes revenue from electric sales when power is delivered to customers. The performance obligation to deliver electricity is generally created and satisfied simultaneously, and the provisions of the regulatory-approved tariff determine the charges OG&E may bill the customer, payment due date and other pertinent rights and obligations of both parties. OG&E measures its customers' metered usage and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues in the balance sheets and in Revenues from Contracts with Customers in the statements of income based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

Integrated Market and Transmission

OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority, but not ownership, of OG&E's transmission facilities to the SPP. The SPP has implemented FERC-approved regional day-ahead and real-time markets for energy and operating services, as well as associated transmission congestion rights. Collectively, the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities.

OG&E records the SPP Integrated Marketplace transactions as sales or purchases per FERC Order 668, which requires that purchases and sales be recorded on a net basis for each settlement period of the SPP Integrated Marketplace. Purchases and sales are based on the fixed transaction price determined by the market at the time of the purchase or sale and the MWh quantity purchased or sold. These results are reported as Revenues from Contracts with Customers or Cost of Sales in the statements of income. OG&E revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operating and regulation by the FERC or the SPP.

OG&E's transmission revenues are generated by the use of OG&E's transmission network by the SPP, which operates the network, on behalf of other transmission owners. OG&E recognizes revenue on the sale of transmission service to its customers over time as the service is provided in the amount OG&E has a right to invoice. Transmission service to the SPP is billed monthly based on a fixed transaction price determined by OG&E's FERC-approved formula transmission rates along with other SPP-specific charges and the megawatt quantity reserved.

Other Revenues

Other Revenues in the statements of income is comprised of certain rider revenue that includes alternative revenue measures as defined in ASC 980, "Regulated Operations," which details two types of alternative revenue programs. The first type adjusts billings for the effects of weather abnormalities or broad external factors or to compensate OG&E for demand-side management initiatives (i.e., no-growth plans and similar conservation efforts). The second type provides for additional billings (i.e., incentive awards) for the achievement of certain objectives, such as reducing costs, reaching specified milestones or demonstratively improving customer service. Once the specific events permitting billing of the additional revenues under either


94

program type have been completed, OG&E recognizes the additional revenues if (i) the program is established by an order from OG&E's regulatory commission that allows for automatic adjustment of future rates; (ii) the amount of additional revenues for the period is objectively determinable and is probable of recovery; and (iii) the additional revenues will be collected within 24 months following the end of the annual period in which they are recognized.

Fuel Adjustment Clauses
 
The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC.

Leases

The Registrants evaluate all contracts under ASC 842 to determine if the contract is or contains a lease and to determine classification as an operating or finance lease. If a lease is identified, the Registrants recognize a right-of-use asset and a lease liability in their balance sheets. The Registrants recognize and measure a lease liability when they conclude the contract contains an identified asset that the Registrants control through having the right to obtain substantially all of the economic benefits and the right to direct the use of the identified asset. The liability is equal to the present value of lease payments, and the asset is based on the liability, subject to adjustment, such as for initial direct costs. Further, the Registrants utilize an incremental borrowing rate for purposes of measuring lease liabilities, if the discount rate is not implicit in the lease. To calculate the incremental borrowing rate, the Registrants start with a current pricing report for their senior unsecured notes, which indicates rates for periods reflective of the lease term, and adjust for the effects of collateral to arrive at the secured incremental borrowing rate. As permitted by ASC 842, the Registrants made an accounting policy election to not apply the balance sheet recognition requirements to short-term leases and to not separate lease components from non-lease components when recognizing and measuring lease liabilities. For income statement purposes, the Registrants record operating lease expense on a straight-line basis.

Income Taxes

OGE Energy files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. OG&E is a part of the consolidated tax return of OGE Energy. Income taxes are generally allocated to each company in the affiliated group, including OG&E, based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and will be amortized to income over the life of the related property. The Registrants use the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Registrants recognize interest related to unrecognized tax benefits in Interest Expense and recognize penalties in Other Expense in the statements of income.

Accrued Vacation
 
The Registrants accrue vacation pay monthly by establishing a liability for vacation earned. Vacation may be taken as earned and is charged against the liability. At the end of each year, the liability represents the amount of vacation earned but not taken.



95

Accumulated Other Comprehensive Income (Loss)
 
The following table presents changes in the components of accumulated other comprehensive income (loss) attributable to OGE Energy during 2019 and 2020. All amounts below are presented net of tax.
Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans
(In millions) Net Gain
 (Loss) 		Net Gain (Loss) Prior Service Cost (Credit) Other Comprehensive Loss from Unconsolidated Affiliates Total
Balance at December 31, 2018 $ (38.8) $ 4.6  $ 5.3  $ —  $ (28.9)
Other comprehensive loss before reclassifications (8.3) (0.2) —  (0.6) (9.1)
Amounts reclassified from accumulated other comprehensive income (loss) 3.4  (0.2) (1.7) —  1.5 
Settlement cost 8.6  —  —  —  8.6 
Net current period other comprehensive income (loss) 3.7  (0.4) (1.7) (0.6) 1.0 
Balance at December 31, 2019 (35.1) 4.2  3.6  (0.6) (27.9)
Other comprehensive income (loss) before reclassifications (5.1) (2.4) —  (0.7) (8.2)
Amounts reclassified from accumulated other comprehensive income (loss) 3.9  (0.1) (1.7) —  2.1 
Curtailment cost —  (0.3) —  —  (0.3)
Settlement cost 2.2  —  —  —  2.2 
Net current period other comprehensive income (loss) 1.0  (2.8) (1.7) (0.7) (4.2)
Balance at December 31, 2020 $ (34.1) $ 1.4  $ 1.9  $ (1.3) $ (32.1)



96

The following table presents significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income (loss) during the years ended December 31, 2020 and 2019.
Details about Accumulated Other Comprehensive Income (Loss) Components Amount Reclassified from Accumulated Other Comprehensive Income (Loss) Affected Line Item in
OGE Energy's Statements of Income
Year Ended December 31,
(In millions) 2020 2019
Amortization of Pension Plan and Restoration of Retirement Income Plan items:
Actuarial losses $ (5.1) $ (4.5) (A)
Settlement cost (2.9) (11.3) (A)
(8.0) (15.8) Income (Loss) Before Taxes
(1.9) (3.8) Income Tax Expense (Benefit)
$ (6.1) $ (12.0) Net Income (Loss)
Amortization of postretirement benefit plans items:
Prior service credit $ 2.3  $ 2.3  (A)
Curtailment cost 0.4  —  (A)
Actuarial gains 0.1  0.2  (A)
2.8  2.5  Income (Loss) Before Taxes
0.7  0.6  Income Tax Expense (Benefit)
$ 2.1  $ 1.9  Net Income (Loss)
Total reclassifications for the period, net of tax $ (4.0) $ (10.1) Net Income (Loss)
(A)These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 13 for additional information).
 
Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation.



97

2.Accounting Pronouncements

Recently Adopted Accounting Standards

The following table presents an overview of recently adopted accounting standards and their impacts on the Registrants.

ASU Number and Name Description Date of Adoption Financial Statements and Disclosures Impact
ASU 2016-13, "Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Information" This standard requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions and reasonable and supportable forecasts in order to record credit losses in a more timely manner. January 1, 2020 Utilizing a modified-retrospective approach, the Registrants determined their only financial instrument requiring measurement under ASU 2016-13 is trade receivables. The Registrants consider both future economic conditions and historical data to measure their reserves for trade receivables under this standard and determined no adjustments to their reserves were necessary upon adoption.
ASU 2018-15, "Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40)" The standard aligns requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. January 1, 2020 The new standard did not have a material effect on the Registrants' financial statements upon adoption. Prospectively, the Registrants record applicable capitalized implementation costs in Other Current Assets in the balance sheets and related amortization expense in Other Operation and Maintenance in the statements of income.
ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework" The standard removes, adds or modifies disclosure requirements that impact all levels of the fair value hierarchy, as well as investments measured using the net asset value practical expedient. January 1, 2020 The Registrants applied the guidance on a retrospective or prospective basis, depending on the requirement, and did not experience a significant impact on their financial statement disclosures.
ASU 2018-14, "Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20)" The standard removes, adds or clarifies disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. January 1, 2020 The Registrants applied the guidance on a retrospective basis and did not experience a significant impact on their financial statement disclosures.
ASU 2020-04, "Reference Rate Reform (Topic 848)"
This standard provides optional expedients and exceptions, if certain criteria are met, for applying GAAP to contracts, hedging relationships and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. January 1, 2020 The guidance did not have a material impact upon adoption, nor do the Registrants expect a material impact in the future, on their financial statements.

The Registrants believe that other recently adopted and recently issued accounting standards that are not yet effective do not appear to have a material impact on the Registrants' financial position, results of operations or cash flows upon adoption.



98

3.Revenue Recognition

The following table presents OG&E's revenues from contracts with customers disaggregated by customer classification. OG&E's operating revenues disaggregated by customer classification can be found in "OG&E (Electric Utility) Results of Operations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
Year Ended December 31,
(In millions) 2020 2019 2018
Residential $ 842.7  $ 865.8  $ 877.8 
Commercial 465.6  486.6  500.0 
Industrial 192.6  217.8  228.9 
Oilfield 169.2  200.4  190.4 
Public authorities and street light 172.3  190.3  197.4 
   System sales revenues 1,842.4  1,960.9  1,994.5 
Provision for rate refund 3.8  (0.9) (6.0)
Integrated market 49.6  38.4  48.7 
Transmission 143.3  148.0  147.4 
Other 30.7  29.1  27.1 
Revenues from contracts with customers $ 2,069.8  $ 2,175.5  $ 2,211.7 

4.Leases

Based on their evaluation of all contracts under ASC 842, as described in Note 1, the Registrants concluded they have operating lease obligations for OG&E's railcar leases, testing equipment and wind farm land leases. OGE Energy also has an operating lease obligation for its office space lease.

Operating Leases

OG&E Railcar Lease Agreement

Effective February 1, 2019, OG&E renewed a railcar lease agreement for 780 rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to fuel expense and are recovered through OG&E's fuel adjustment clauses. On February 1, 2024, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $6.8 million.

OG&E Testing Equipment Lease Agreement

Effective January 1, 2020, OG&E entered into a noncancellable engineering testing equipment lease agreement, with a term of January 1, 2020 to December 31, 2022.

OG&E Wind Farm Land Lease Agreements

OG&E has operating leases related to land for OG&E's Centennial, OU Spirit and Crossroads wind farms with terms of 25 to 30 years. The Centennial lease has rent escalations which increase annually based on the Consumer Price Index. While lease liabilities are not remeasured as a result of changes to the Consumer Price Index, changes to the Consumer Price Index are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. The OU Spirit and Crossroads leases have rent escalations which increase after five and 10 years. Although the leases are cancellable, OG&E is required to make annual lease payments as long as the wind turbines are located on the land. OG&E does not expect to terminate the leases until the wind turbines reach the end of their useful life.



99

OGE Energy Office Space Lease

OGE Energy has a noncancellable office space lease agreement, with a term from September 1, 2018 to August 31, 2021, that allows for leasehold improvements.

Financial Statement Information and Maturity Analysis of Lease Liabilities

OGE Energy's operating lease cost was $6.4 million, $6.0 million and $4.9 million for the years ended December 31, 2020, 2019 and 2018, respectively. OG&E's operating lease cost was $5.5 million, $5.1 million and $4.1 million for the years ended December 31, 2020, 2019 and 2018, respectively.

The following table presents amounts recognized for operating leases in the Registrants' cash flow statements and balance sheets and supplemental information related to those amounts recognized.
OGE Energy OG&E
Year Ended December 31, Year Ended December 31,
(In millions) 2020 2019 2020 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases $ 6.4 $ 5.6 $ 5.5 $ 4.8
Right-of-use assets obtained in exchange for new operating lease liabilities $ 1.4 $ 10.7 $ 1.4 $ 10.7
(Dollars in millions) December 31, 2020 December 31, 2019 December 31, 2020 December 31, 2019
Right-of-use assets at period end (A) $ 37.6 $ 40.9 $ 37.0 $ 39.6
Operating lease liabilities at period end (B) $ 42.3 $ 45.8 $ 41.7 $ 44.3
Operating lease weighted-average remaining lease term (in years)
12.5 13.1 12.7 13.5
Operating lease weighted-average discount rate 3.9  % 3.9  % 3.9  % 3.9  %
(A)Included in Property, Plant and Equipment in the Registrants' balance sheets.
(B)Included in Other Deferred Credits and Other Liabilities in the Registrants' balance sheets.

The following table presents a maturity analysis of the Registrants' operating lease liabilities.
Future minimum operating lease payments as of December 31: OGE Energy OG&E
(In millions)
2021 $ 6.3  $ 5.7 
2022 5.7  5.7 
2023 5.1  5.1 
2024 3.2  3.2 
2025 3.0  3.0 
Thereafter 31.7  31.7 
Total future minimum lease payments 55.0  54.4 
Less: Imputed interest 12.7  12.7 
Present value of net minimum lease payments $ 42.3  $ 41.7 




100

5.Investment in Unconsolidated Affiliates

In 2013, OGE Energy, CenterPoint and the ArcLight group formed Enable as a private limited partnership, and OGE Energy and the ArcLight group indirectly contributed 100 percent of the equity interests in Enogex LLC to Enable. OGE Energy determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and recorded the contribution at historical cost. The formation of Enable was considered a business combination, and CenterPoint was the acquirer of Enogex Holdings for accounting purposes. Under this method, the fair value of the consideration paid by CenterPoint for Enogex Holdings was allocated to the assets acquired and liabilities assumed based on their fair value. Enogex Holdings' assets, liabilities and equity were accordingly adjusted to estimated fair value, resulting in an increase to Enable's equity of $2.2 billion. Since the contribution of Enogex LLC to Enable was recorded at historical cost, the effects of the amortization and depreciation expense associated with the fair value adjustments on Enable's results of operations have been eliminated in OGE Energy's recording of its equity in earnings of Enable. As prior real estate sales accounting guidance was superseded by ASU 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets," OGE Energy recognizes gains or losses on sales or dilution events in its investment in Enable within OGE Energy's earnings, net of proportional basis difference recognition.

At December 31, 2020, OGE Energy owned 111.0 million common units, or 25.5 percent, of Enable's outstanding common units. On December 31, 2020, Enable's common unit price closed at $5.26. OGE Energy recorded equity in losses of unconsolidated affiliates of $668.0 million for the year ended December 31, 2020 compared to equity in earnings of unconsolidated affiliates of $113.9 million and $152.8 million for the years ended 2019 and 2018, respectively. Equity in earnings (losses) of unconsolidated affiliates includes OGE Energy's share of Enable's earnings adjusted for the amortization of the basis difference of OGE Energy's original investment in Enogex LLC and its underlying equity in the net assets of Enable, as well as any impairment OGE Energy records on its investment in Enable. Equity in earnings (losses) of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described above. These amortizations may also include gain or loss on dilution, net of proportional basis difference recognition.

OGE Energy evaluates its equity method investment for impairment when factors indicate that a decline in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. An impairment loss, based on the excess of the carrying value over estimated fair value of the investment, is recognized in earnings when an impairment is deemed to be other than temporary. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. Effective March 31, 2020, OGE Energy estimated the fair value of its investment in Enable was below the book value and concluded the decline in value was not temporary due to the severity of the decline and the recent rapid deterioration, as well as the near term future outlook, of the midstream oil and gas industry. Accordingly, OGE Energy recorded a $780.0 million impairment on its investment in Enable in March 2020, which is included in Equity in Earnings (Losses) of Unconsolidated Affiliates in OGE Energy's 2020 income statement. Further information concerning the fair value method used to measure the impairment on OGE Energy's investment in Enable can be found in Note 7.

The following tables present summarized unaudited financial information for 100 percent of Enable as of December 31, 2020 and 2019 and for the years ended December 31, 2020, 2019 and 2018.
December 31,
Balance Sheet 2020 2019
(In millions)
Current assets $ 381  $ 389 
Non-current assets $ 11,348  $ 11,877 
Current liabilities $ 582  $ 780 
Non-current liabilities $ 4,052  $ 4,077 

Year Ended December 31,
Income Statement 2020 2019 2018
(In millions)
Total revenues $ 2,463  $ 2,960  $ 3,431 
Cost of natural gas and NGLs $ 965  $ 1,279  $ 1,819 
Operating income $ 465  $ 569  $ 648 
Net income $ 52  $ 360  $ 485 


101


The following table presents a reconciliation of OGE Energy's equity in earnings (losses) of unconsolidated affiliates for the years ended December 31, 2020, 2019 and 2018. For further discussion of Enable's net income, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - OGE Holdings (Natural Gas Midstream Operations)."
Year Ended December 31,
(In millions) 2020 2019 2018
Enable net income $ 52.0  $ 360.0  $ 485.3 
OGE Energy's percent ownership at period end 25.5  % 25.5  % 25.6  %
OGE Energy's portion of Enable net income $ 13.2  $ 91.8  $ 124.4 
Amortization of basis difference and dilution recognition (A) 98.8  22.1  28.4 
Impairment of OGE Energy's equity method investment in Enable (780.0) —  — 
Equity in earnings (losses) of unconsolidated affiliates (B) $ (668.0) $ 113.9  $ 152.8 
(A) Includes loss on dilution, net of proportional basis difference recognition.
(B)For the year ended December 31, 2020, Enable recorded a $225.0 million impairment on its SESH equity method investment. Enable estimated the fair value of this equity method investment was below the carrying value at September 30, 2020 and concluded the decline in value was other than temporary due to the expiration of a transportation contract and the current status of renewal negotiations. The impairment ran through OGE Energy's portion of Enable net income and was offset by basis differences that flow through the amortization of basis difference and dilution recognition line item above.

The following table presents a reconciliation of the difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable (basis difference) from December 31, 2019 to December 31, 2020. The basis difference is being amortized over approximately 30 years.
(In millions)
Basis difference at December 31, 2019 $ 652.5 
Amortization of basis difference (A) (100.2)
Impairment of OGE Energy's equity method investment in Enable 780.0 
Basis difference at December 31, 2020 $ 1,332.3 
(A) Includes proportional basis difference recognition due to dilution.

On April 1, 2020, Enable announced a 50 percent reduction to its quarterly distribution in order to strengthen its balance sheet and increase its annualized retained cash flow. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Recent Developments" for further discussion of OGE Energy's response.

On February 12, 2021, Enable announced a quarterly dividend distribution of $0.16525 per unit on its outstanding common units, which is unchanged from the previous quarter. If cash distributions to Enable's unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. OGE Energy is entitled to 60 percent of those "incentive distributions." In certain circumstances, the general partner has the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable's cash distributions at the time of the exercise of this reset election.

Distributions received from Enable were $91.7 million, $144.0 million and $141.2 million during the years ended December 31, 2020, 2019 and 2018, respectively.

On February 16, 2021, Enable entered into a definitive merger agreement with Energy Transfer, pursuant to which, and subject to the conditions of the merger agreement, all outstanding common units of Enable will be acquired by Energy Transfer in an all-equity transaction. Under the terms of the merger agreement, Enable's common unitholders, including OGE Energy, will receive 0.8595 of one common unit representing limited partner interests in Energy Transfer for each common unit of Enable. The transaction is anticipated to close in 2021. The transaction is subject to the receipt of the required approvals from the holders of a majority of Enable's common units, anti-trust approvals and other customary closing conditions. Assuming the transaction closes, OGE Energy will own approximately three percent of Energy Transfer's outstanding limited partner units in lieu of the 25.5 percent interest in Enable that it currently owns.


102


Contemporaneously with the execution of the merger agreement, OGE Energy entered into a support agreement with Enable and Energy Transfer in which OGE Energy has agreed to vote its common units in favor of the merger. In addition, the merger agreement contemplates a registration rights agreement with Energy Transfer to be executed at the closing of the merger that provides for customary resale registration, demand registration and piggy-back registration rights with respect to Energy Transfer common units issued to OGE Energy in the merger.

6.Related Party Transactions

OGE Energy charges operating costs to OG&E and Enable based on several factors, and operating costs directly related to OG&E and/or Enable are assigned as such. Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method, which is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment.

OGE Energy and OG&E

OGE Energy charged operating costs to OG&E of $140.6 million, $149.8 million and $140.9 million during the years ended December 31, 2020, 2019 and 2018, respectively. In 2020 and 2018, OG&E declared dividends to OGE Energy of $325.0 million and $185.0 million, respectively. In 2019, no dividends were declared from OG&E to OGE Energy.

OGE Energy and Enable

OGE Energy and Enable are currently parties to several agreements whereby OGE Energy provides specified support services to Enable, such as certain information technology, payroll and benefits administration. Under these agreements, OGE Energy charged operating costs to Enable of $0.4 million, $0.5 million and $0.6 million for December 31, 2020, 2019 and 2018, respectively.

Pursuant to a seconding agreement, OGE Energy provides seconded employees to Enable to support Enable's operations. As of December 31, 2020, 76 employees that participate in OGE Energy's defined benefit and retirement plans are seconded to Enable. OGE Energy billed Enable for reimbursement of $17.3 million, $23.2 million and $27.5 million in 2020, 2019 and 2018, respectively, under the seconding agreement for employment costs. If the seconding agreement were terminated, and those employees were no longer employed by OGE Energy, and lump sum payments were made to those employees, OGE Energy would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at OGE Energy by $19.0 million. Settlement and curtailment charges associated with the Enable seconded employees are not reimbursable to OGE Energy by Enable. The seconding agreement can be terminated by mutual agreement of OGE Energy and Enable or solely by OGE Energy upon 120 days' notice.

OGE Energy had accounts receivable from Enable for amounts billed for support services, including the cost of seconded employees, of $2.0 million and $0.8 million as of December 31, 2020 and 2019, which are included in Accounts Receivable in OGE Energy's balance sheets.

Assuming the pending merger between Enable and Energy Transfer is completed, these agreements between OGE Energy and Enable pursuant to which OGE Energy provides support services and seconded employees will be terminated.

OG&E and Enable

Enable provides gas transportation services to OG&E pursuant to agreements, which expire in May 2024 and December 2038, that grant Enable the responsibility of delivering natural gas to OG&E's generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable's deliveries exceed OG&E's pipeline receipts. Enable purchases gas from OG&E when OG&E's pipeline receipts exceed Enable's deliveries. Further, an additional gas transportation services contract with Enable became effective in December 2018 related to the project to convert Muskogee Units 4 and 5 from coal to natural gas. The following table presents summarized related party transactions between OG&E and Enable during the years ended December 31, 2020, 2019 and 2018.



103

Year Ended December 31,
(In millions) 2020 2019 2018
Operating revenues:
Electricity to power electric compression assets $ 15.1  $ 15.9  $ 16.3 
Cost of sales:
Natural gas transportation services $ 32.8  $ 41.2  $ 37.9 
Natural gas purchases (sales) $ 2.7  $ (6.0) $ (3.2)

7.Fair Value Measurements
 
The classification of the Registrants' fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels defined in the fair value hierarchy are as follows:
 
Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date.
 
Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.  
 
Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

The Registrants had no financial instruments measured at fair value on a recurring basis at December 31, 2020 and 2019. The following table presents the carrying amount and fair value of the Registrants' financial instruments at December 31, 2020 and 2019, as well as the classification level within the fair value hierarchy.
  2020 2019
December 31 (In millions)
Carrying Amount  Fair
Value 		Carrying Amount   Fair
Value 		Classification
Long-term Debt (including Long-term Debt due within one year):    
OG&E Senior Notes $ 3,349.6  $ 4,182.1  $ 3,050.3  $ 3,500.4  Level 2
OG&E Industrial Authority Bonds $ 135.4  $ 135.4  $ 135.4  $ 135.4  Level 2
Tinker Debt $ 9.4  $ 10.7  $ 9.5  $ 10.0  Level 3

Nonrecurring Fair Value Measurements

As further discussed in Note 5, OGE Energy recorded an impairment on its investment in Enable in March 2020. The nonrecurring fair value measurement consisted of calculating a 20-trading day volume weighted average price for Enable's common units through March 31, 2020. This method of valuation was determined to be representative of the fair value of Enable's common units as it incorporated market prices during the period and reduced the impact of volatility that a single day could represent. OGE Energy concluded that this valuation method resulted in a Level 3 nonrecurring fair value measurement.



104

8.Stock-Based Compensation

In 2013, OGE Energy adopted, and its shareholders approved, the Stock Incentive Plan. Under the Stock Incentive Plan, restricted stock, restricted stock units, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of OGE Energy and its subsidiaries, including OG&E. OGE Energy has authorized the issuance of up to 7,400,000 shares under the Stock Incentive Plan.

The following table presents the Registrants' pre-tax compensation expense and related income tax benefit for the years ended December 31, 2020, 2019 and 2018 related to performance units and restricted stock units for the Registrants' employees.
OGE Energy OG&E
Year Ended December 31 (In millions)
2020 2019 2018 2020 2019 2018
Performance units:      
Total shareholder return $ 7.9  $ 8.7  $ 8.2  $ 2.3  $ 3.0  $ 2.8 
Earnings per share 1.0  4.3  5.1  0.3  1.5  1.8 
Total performance units 8.9  13.0  13.3  2.6  4.5  4.6 
Restricted stock units 0.9  0.9  0.1  0.4  0.4  — 
Total compensation expense $ 9.8  $ 13.9  $ 13.4  $ 3.0  $ 4.9  $ 4.6 
Income tax benefit $ 2.5  $ 3.6  $ 3.4  $ 0.8  $ 1.3  $ 1.2 

During the year ended December 31, 2020, OGE Energy purchased 405,000 shares of its common stock, and 247,252 of these shares were used during the same period to satisfy payouts of earned performance units and restricted stock unit grants to the Registrants' employees pursuant to OGE Energy's Stock Incentive Plan. OGE Energy intends to use the remaining shares to satisfy payouts of earned performance units and restricted stock unit grants to employees pursuant to its Stock Incentive Plan. The shares were purchased at an average cost of $38.04 and $33.14 per share on the open market during March 2020 and August 2020, respectively. OGE Energy records treasury stock purchases at cost. Treasury stock is presented as a reduction of stockholders' equity in OGE Energy's 2020 balance sheet.

During the year ended December 31, 2020, there was an immaterial number of shares of new common stock issued pursuant to OGE Energy's Stock Incentive Plan to satisfy restricted stock unit grants to employees.

Performance Units
 
Under the Stock Incentive Plan, OGE Energy has issued performance units which represent the value of one share of OGE Energy's common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with OGE Energy or a subsidiary prior to the end of the primarily three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant's number of full months of service during the award cycle, further adjusted based on the achievement of the performance goals during the award cycle. The Registrants estimate expected forfeitures in accounting for performance unit compensation expense.
 
The performance units granted based on total shareholder return are contingently awarded and will be payable in shares of OGE Energy's common stock subject to the condition that the number of performance units, if any, earned by the employees upon the expiration of a primarily three-year award cycle (i.e., three-year cliff vesting period) is dependent on OGE Energy's total shareholder return ranking relative to a peer group of companies. The performance units granted based on earnings per share are contingently awarded and will be payable in shares of OGE Energy's common stock based on OGE Energy's earnings per share growth over a primarily three-year award cycle (i.e., three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of OGE Energy's Board of Directors. All of these performance units are classified as equity in the balance sheets. If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. Payout requires approval of the Compensation Committee of OGE Energy's Board of Directors. Payouts, if any, are all made in common stock and are considered made when the payout is approved by the Compensation Committee.



105

Performance Units – Total Shareholder Return
 
The fair value of the performance units based on total shareholder return was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the primarily three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Dividends are accrued on a quarterly basis pending achievement of payout criteria and are included in the fair value calculations. Expected price volatility is based on the historical volatility of OGE Energy's common stock for the past three years and is simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the award cycle. There are no post-vesting restrictions related to OGE Energy's performance units based on total shareholder return. The following table presents the number of performance units granted based on total shareholder return and the assumptions used to calculate the grant date fair value of the performance units based on total shareholder return.
OGE Energy OG&E
  2020 2019 2018 2020 2019 2018
Number of units granted 201,552 208,647 261,916 67,975 68,396 91,940
Fair value of units granted $ 38.03 $ 47.00 $ 36.86 $ 38.03 $ 47.00 $ 36.86
Expected dividend yield 3.5  % 4.0  % 3.6  % 3.5  % 4.0  % 3.6  %
Expected price volatility 15.0  % 17.0  % 19.0  % 15.0  % 17.0  % 19.0  %
Risk-free interest rate 1.17  % 2.47  % 2.38  % 1.17  % 2.47  % 2.38  %
Expected life of units (in years)
2.85 2.86 2.86 2.85 2.86 2.86

Performance Units – Earnings Per Share

The fair value of the performance units based on earnings per share is based on grant date fair value which is equivalent to the price of one share of OGE Energy's common stock on the date of grant. The fair value of performance units based on earnings per share varies as the number of performance units that will vest is based on the grant date fair value of the units and the probable outcome of the performance condition. OGE Energy reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable. As a result, the compensation expense recognized for these performance units can vary from period to period. There are no post-vesting restrictions related to OGE Energy's performance units based on earnings per share. In 2019, the Compensation Committee of OGE Energy's Board of Directors voted to grant restricted stock units in lieu of performance units based on earnings per share. For 2018, 87,308 and 30,649 performance units based on earnings per share were granted to OGE Energy and OG&E employees, respectively, and the grant date fair value for such units granted was $31.03.

Restricted Stock Units
 
Under the Stock Incentive Plan, OGE Energy has issued restricted stock units to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace, and as of the 2019 grant cycle, restricted stock units are granted in lieu of performance units based on earnings per share. The restricted stock units vest primarily in a three-year award cycle (i.e., three-year cliff vesting period). Prior to vesting, each restricted stock unit is subject to forfeiture if the recipient ceases to render substantial services to OGE Energy or a subsidiary. These restricted stock units may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.

The fair value of the restricted stock units was based on the closing market price of OGE Energy's common stock on the grant date. Compensation expense for the restricted stock units is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a primarily three-year vesting period. Also, for those restricted stock units that vest in one-third annual increments over a three-year cycle, OGE Energy treats its restricted stock units as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period.



106

Dividends will only be paid on restricted stock unit awards that vest; therefore, only the present value of dividends expected to vest are included in the fair value calculations. The expected life of the restricted stock units is based on the non-vested period since inception of the primarily three-year award cycle. There are no post-vesting restrictions related to OGE Energy's restricted stock units. The following table presents the number of restricted stock units granted and the grant date fair value.
OGE Energy OG&E
  2020 2019 2018 2020 2019 2018
Restricted stock units granted 67,193  75,929  826  22,665  26,141  — 
Fair value of restricted stock units granted $ 43.69  $ 41.71  $ 36.28  $ 43.69  $ 41.63  $ — 

Performance Units and Restricted Stock Units Activity

The following tables present a summary of the activity for the Registrants' performance units and restricted stock units for the year ended December 31, 2020.
OGE Energy Performance Units Restricted
Stock Units
Total Shareholder Return Earnings Per Share
(Dollars in millions) Number
of Units 		Aggregate Intrinsic Value Number
of Units 		Aggregate Intrinsic Value Number
of Shares 		Aggregate Intrinsic Value
Units/shares outstanding at 12/31/19 664,817  155,171  72,880 
Granted 201,552  (A) —  67,193 
Converted (222,163) (B) $ 11.5  (74,053) (B) $ 6.6  N/A
Vested N/A N/A (2,608) $ (0.1)
Forfeited (31,944) (2,116) (12,546)
Units/shares outstanding at 12/31/20 612,262  $ 5.4  79,002  $ 2.7  124,919  $ 4.0 
Units/shares fully vested at 12/31/20 236,990  $ 5.4  79,002  $ 2.7  1,752 $ 0.1 

OG&E Performance Units Restricted
Stock Units
Total Shareholder Return Earnings Per Share
(Dollars in millions) Number
of Units 		Aggregate Intrinsic Value Number
of Units 		Aggregate Intrinsic Value Number
of Shares 		Aggregate Intrinsic Value
Units/shares outstanding at 12/31/19 227,679  53,977  25,005 
Granted 67,975  (A) —  22,665 
Converted (77,799) (B) $ 4.0  (25,931) (B) $ 2.3  N/A
Vested N/A N/A (1,113) $ — 
Forfeited (28,985) (1,969) (11,100)
Employee migration (6,507) (C) (842) (C) (1,327) (C)
Units/shares outstanding at 12/31/20 182,363  $ 1.7  25,235  $ 0.8  34,130  $ 1.1 
Units/shares fully vested at 12/31/20 75,693  $ 1.7  25,235  $ 0.8  1,114 $ — 
(A)For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target.
(B)These amounts represent performance units that vested at December 31, 2019 which were settled in March 2020.
(C)Due to certain employees transferring between OG&E and OGE Energy.



107

The following tables present a summary of the activity for the Registrants' non-vested performance units and restricted stock units for the year ended December 31, 2020.
OGE Energy Performance Units Restricted
Stock Units
Total Shareholder Return Earnings Per Share
Number
of Units 		Weighted-Average
Grant Date
Fair Value 		Number
of Units 		Weighted-Average
Grant Date
Fair Value 		Number
of Shares 		Weighted-Average
Grant Date
Fair Value
Units/shares non-vested at 12/31/19 442,654  $ 41.43  81,118  $ 31.03  72,880  $ 41.66 
Granted 201,552  (A) $ 38.03  —  $ —  67,193  $ 43.69 
Vested (236,990) $ 36.86  (79,002) $ 31.03  (2,608) $ 40.30 
Forfeited (31,944) $ 41.15  (2,116) $ 31.03  (12,546) $ 42.60 
Units/shares non-vested at 12/31/20 375,272  $ 42.51  —  $ —  124,919  $ 42.69 

OG&E Performance Units Restricted
Stock Units
Total Shareholder Return Earnings Per Share
Number
of Units 		Weighted-Average
Grant Date
Fair Value 		Number
of Units 		Weighted-Average
Grant Date
Fair Value 		Number
of Shares 		Weighted-Average
Grant Date
Fair Value
Units/shares non-vested at 12/31/19 149,880  $ 41.31  28,046  $ 31.03  25,005  $ 41.62 
Granted 67,975  (A) $ 38.03  —  $ —  22,665  $ 43.69 
Vested (75,693) $ 36.86  (25,235) $ 31.03  (1,113) $ 40.59 
Forfeited (28,985) $ 41.12  (1,969) $ 31.03  (11,100) $ 42.60 
Employee migration (6,507) (B) $ 40.26  (842) (B) $ 31.03  (1,327) (B) $ 42.76 
Units/shares non-vested at 12/31/20 106,670  $ 42.49  —  $ —  34,130  $ 42.67 
(A)For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target.
(B)Due to certain employees transferring between OG&E and OGE Energy.

Fair Value of Vested Performance Units and Restricted Stock Units

The following table presents a summary of the Registrants' fair value for vested performance units and restricted stock units.
OGE Energy OG&E
Year Ended December 31 (In millions)
2020 2019 2018 2020 2019 2018
Performance units:
Total shareholder return $ 8.7  $ 9.3  $ 5.9  $ 2.8  $ 3.2  $ 2.1 
Earnings per share $ 2.5  $ 5.2  $ 4.9  $ 0.8  $ 0.9  $ 1.7 
Restricted stock units $ 0.1  $ 0.1  $ 0.1  $ 0.1  $ —  $ — 



108

Unrecognized Compensation Cost

The following table presents a summary of the Registrants' unrecognized compensation cost for non-vested performance units and restricted stock units and the weighted-average periods over which the compensation cost is expected to be recognized.
OGE Energy OG&E
December 31, 2020
Unrecognized Compensation Cost (In millions)
Weighted Average to be Recognized (In years)
Unrecognized Compensation Cost (In millions)
Weighted Average to be Recognized (In years)
Performance units - total shareholder return $ 7.1  1.62 $ 1.8  1.64
Restricted stock units 1.6  1.65 0.4  1.68
Total unrecognized compensation cost $ 8.7  $ 2.2 

9.Income Taxes
 
Income Tax Expense (Benefit)

The following table presents the components of income tax expense (benefit). 
OGE Energy OG&E
Year Ended December 31 (In millions)
2020 2019 2018 2020 2019 2018
Provision (benefit) for current income taxes:       
Federal $ 8.4  $ (6.4) $ (1.9) $ (3.8) $ (7.9) $ (12.4)
State 0.5  5.1  (4.4) (0.6) 4.1  (4.1)
Total provision (benefit) for current income taxes  8.9  (1.3) (6.3) (4.4) (3.8) (16.5)
Provision (benefit) for deferred income taxes, net:       
Federal (105.2) 48.5  74.7  45.7  37.7  53.7 
State (31.1) (17.4) 3.7  (6.6) (13.8) 2.7 
Total provision (benefit) for deferred income taxes, net  (136.3) 31.1  78.4  39.1  23.9  56.4 
Deferred federal investment tax credits, net —  —  0.1  —  —  0.1 
Total income tax expense (benefit) $ (127.4) $ 29.8  $ 72.2  $ 34.7  $ 20.1  $ 40.0 
 
OGE Energy files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. OG&E is a part of the consolidated income tax return of OGE Energy. With few exceptions, the Registrants are no longer subject to U.S. federal tax or state and local examinations by tax authorities for years prior to 2017. Income taxes are generally allocated to each company in the affiliated group, including OG&E, based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and will be amortized to income over the life of the related property. Additionally, OG&E earns federal tax credits associated with production from its wind facilities. Oklahoma production and investment state tax credits are also earned on investments in electric and solar generating facilities which further reduce OG&E's effective tax rate.



109

The following table presents a reconciliation of the statutory tax rates to the effective income tax rate.
OGE Energy OG&E
Year Ended December 31 2020 2019 2018 2020 2019 2018
Statutory federal tax rate 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  %
Impairment of OGE Energy's investment in Enable (A) 31.6  —  —  —  —  — 
Remeasurement of state deferred tax liabilities 0.9  (0.8) (0.4) —  —  — 
Executive compensation limitation 0.2  0.2  0.2  —  —  — 
Other 0.1  (0.7) 0.4  0.1  (0.6) (0.1)
Federal renewable energy credit (B) (5.0) (6.0) (5.1) (5.4) (7.6) (6.9)
Amortization of net unfunded deferred taxes (4.4) (4.5) (2.1) (4.8) (5.6) (2.9)
State income taxes, net of federal income tax
benefit 		(1.4) (1.2) 0.4  (1.6) (1.8) (0.2)
Stock-based compensation (0.3) (1.2) —  —  —  — 
401(k) dividends (0.4) (0.4) (0.3) —  —  — 
Federal deferred tax revaluation —  —  0.4  —  —  — 
Effective income tax rate 42.3  % 6.4  % 14.5  % 9.3  % 5.4  % 10.9  %
(A)As further discussed in Note 5, OGE Energy recorded a $780.0 million impairment on its investment in Enable in March 2020, which resulted in a tax benefit being recorded that caused a significant variance to the effective tax rate as compared to the prior year. This variance has been presented in the table as a single line item in order to facilitate comparability of other components of the effective tax rate.
(B)Represents credits primarily associated with the production from OG&E's wind farms.

The deferred tax provisions are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by OG&E. The following table presents the components of Deferred Income Taxes at December 31, 2020 and 2019.
OGE Energy OG&E
December 31 (In millions)
2020 2019 2020 2019
Deferred income tax liabilities, net:
Accelerated depreciation and other property related differences $ 1,721.2  $ 1,656.8  $ 1,721.2  $ 1,656.8 
Investment in Enable 302.6  478.2  —  — 
Regulatory assets 52.3  28.4  52.3  28.4 
Pension Plan 3.9  4.1  27.4  24.5 
Bond redemption-unamortized costs 2.0  2.2  2.0  2.2 
Derivative instruments 1.7  1.6  —  — 
Federal tax credits (236.6) (238.0) (236.6) (238.0)
Income taxes recoverable from customers, net (221.8) (229.9) (221.8) (229.9)
State tax credits (204.4) (185.8) (189.0) (170.8)
Regulatory liabilities (81.0) (68.1) (81.0) (68.1)
Postretirement medical and life insurance benefits (22.4) (23.3) (15.3) (16.0)
Asset retirement obligations (20.3) (19.2) (20.3) (19.2)
Net operating losses (12.0) (16.6) (1.4) (5.7)
Accrued liabilities (9.6) (10.7) (5.2) (4.3)
Deferred federal investment tax credits (2.7) (1.8) (2.7) (1.8)
Accrued vacation (2.2) (2.1) (1.6) (1.6)
Other (1.4) 0.4  (6.5) (4.7)
Uncollectible accounts (0.7) (0.4) (0.7) (0.4)
Total deferred income tax liabilities, net $ 1,268.6  $ 1,375.8  $ 1,020.8  $ 951.4 



110

As of December 31, 2020, the Registrants have classified $17.6 million of unrecognized tax benefits as a reduction of deferred tax assets recorded. Management is currently unaware of any issues under review that could result in significant additional payments, accruals or other material deviation from this amount.

The following table presents a reconciliation of the Registrants' total gross unrecognized tax benefits as of the years ended December 31, 2020, 2019 and 2018.
(In millions) 2020 2019 2018
Balance at January 1 $ 20.7  $ 20.7  $ 20.7 
Tax positions related to current year:
Additions 1.2  —  — 
Balance at December 31 $ 21.9  $ 20.7  $ 20.7 

As of December 31, 2020, 2019 and 2018, there were $17.6 million, $16.4 million and $16.4 million, respectively, of unrecognized tax benefits that, if recognized, would affect the annual effective tax rate.

Where applicable, the Registrants classify income tax-related interest and penalties as interest expense and other expense, respectively. During the year ended December 31, 2020, there were no income tax-related interest or penalties recorded with regard to uncertain tax positions.
The Registrants recognize tax benefits from an uncertain tax position only if it is more likely than not the tax position will be sustained on examination by taxing authorities based on the technical merits of the position. The tax benefits in the financial statements from such positions are then measured based on the largest benefit that has a greater than 50 percent likelihood of being realized on settlement. As a result of those measurements, in September 2020, the Registrants recorded an additional reserve for certain federal research and development credits in the amount of $1.2 million.
The Registrants sustained federal and state tax operating losses through 2012 caused primarily by bonus depreciation and other book versus tax temporary differences. Federal net operating losses generated during those years have been fully utilized. State operating losses are being carried forward for utilization in future years. In addition to the tax operating losses, the Registrants were unable to utilize the various tax credits that were generated during those years. These tax losses and credits are being carried as deferred tax assets and will be utilized in future periods. Under current law, the Registrants anticipate future taxable income will be sufficient to utilize remaining losses and credits before they begin to expire after 2020. The following table presents a summary of these carry forwards.
OGE Energy OG&E
(In millions) Carry Forward Amount Deferred Tax Asset Carry Forward Amount Deferred Tax Asset Earliest Expiration Date
State operating loss $ 268.0  $ 12.0  $ 21.5  $ 1.4  2030
Federal tax credits $ 236.6  $ 236.6  $ 236.6  $ 236.6  2032
State tax credits:
Oklahoma investment tax credits $ 205.6  $ 162.3  $ 186.1  $ 147.0  N/A
Oklahoma capital investment board credits $ 12.7  $ 12.7  $ 12.7  $ 12.7  N/A
Oklahoma zero emission tax credits $ 37.2  $ 29.3  $ 37.2  $ 29.3  2021
Louisiana inventory credits $ 0.2  $ 0.1  $ —  $ —  2021
N/A - not applicable

10.Common Equity

OGE Energy

Automatic Dividend Reinvestment and Stock Purchase Plan
 
OGE Energy issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan in 2020. OGE Energy may, from time to time, issue shares under its Automatic Dividend Reinvestment and Stock Purchase Plan or purchase shares traded on the open market. At December 31, 2020, there were 4,774,442 shares of unissued common stock reserved for issuance under OGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan.


111


Earnings (Loss) Per Share
 
Basic earnings (loss) per share is calculated by dividing net income (loss) attributable to OGE Energy by the weighted average number of OGE Energy's common shares outstanding during the period. In the calculation of diluted earnings (loss) per share, weighted average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for OGE Energy consist of performance units and restricted stock units. The following table presents the calculation of basic and diluted earnings (loss) per share for OGE Energy.
(In millions except per share data) 2020 2019 2018
Net income (loss) $ (173.7) $ 433.6  $ 425.5 
Average common shares outstanding:    
Basic average common shares outstanding 200.1  200.1  199.7 
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units) —  0.6  0.8 
Diluted average common shares outstanding 200.1  200.7  200.5 
Basic earnings (loss) per average common share $ (0.87) $ 2.17  $ 2.13 
Diluted earnings (loss) per average common share $ (0.87) $ 2.16  $ 2.12 
Anti-dilutive shares excluded from earnings per share calculation 0.3  —  — 
 
Dividend Restrictions

OGE Energy's Certificate of Incorporation places restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Before OGE Energy can pay any dividends on its common stock, the holders of any of its preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. As there is no preferred stock outstanding, that restriction did not place any effective limit on OGE Energy's ability to pay dividends to its shareholders.

OGE Energy utilizes receipts from its equity investment in Enable and dividends from OG&E to pay dividends to its shareholders. Enable's partnership agreement requires that it distribute all "available cash," as defined as cash on hand at the end of a quarter after the payment of expenses and the establishment of cash reserves and cash on hand resulting from working capital borrowings made after the end of the quarter.

Pursuant to the leverage restriction in OGE Energy's revolving credit agreement, OGE Energy must maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $815.0 million of OGE Energy's retained earnings from being paid out in dividends. Accordingly, approximately $1.7 billion of OGE Energy's retained earnings as of December 31, 2020 are unrestricted for the payment of dividends.

OG&E

There were no new shares of OG&E common stock issued in 2020, 2019 or 2018.

Dividend Restrictions

Pursuant to the Federal Power Act, OG&E is restricted from paying dividends from its capital accounts. Dividends are paid from retained earnings. Pursuant to the leverage restriction in OG&E's revolving credit agreement, OG&E must also maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $842.7 million of OG&E's retained earnings from being paid out in dividends. Accordingly, approximately $2.1 billion of OG&E's retained earnings as of December 31, 2020 are unrestricted for the payment of dividends.

11.Long-Term Debt
 
A summary of the Registrants' long-term debt is included in the statements of capitalization. The Registrants have no long-term debt maturing in the next five years. At December 31, 2020, the Registrants were in compliance with all of their debt agreements.



112

The Registrants have previously incurred costs related to debt refinancing. Unamortized loss on reacquired debt is classified as a Non-Current Regulatory Asset in the balance sheets. Unamortized debt expense and unamortized premium and discount on long-term debt are classified as Long-Term Debt in the balance sheets and are being amortized over the life of the respective debt.

OG&E Industrial Authority Bonds

OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day. The following table presents information about these bonds, which can be tendered at the option of the holder during the next 12 months.
Series Date Due Amount
    (In millions)
0.28% - 5.35%
Garfield Industrial Authority, January 1, 2025
$ 47.0 
0.33% - 4.31%
Muskogee Industrial Authority, January 1, 2025
32.4 
0.28% - 5.35%
Muskogee Industrial Authority, June 1, 2027
56.0 
Total (redeemable during next 12 months) $ 135.4 

All of these bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the bond by delivering an irrevocable notice to the tender agent stating the principal amount of the bond, payment instructions for the purchase price and the business day the bond is to be purchased. The repayment option may only be exercised by the holder of a bond for the principal amount. When a tender notice has been received by the trustee, a third-party remarketing agent for the bonds will attempt to remarket any bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such bonds, OG&E is obligated to repurchase such unremarketed bonds. As OG&E has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as Long-Term Debt in the balance sheets. OG&E believes that it has sufficient liquidity to meet these obligations.

Issuance of Long-Term Debt

In April 2020, OG&E issued $300.0 million of 3.25 percent senior notes due April 1, 2030. The proceeds from the issuance were added to OG&E's general funds to be used for general corporate purposes, including to fund ongoing capital expenditures and working capital.

12.Short-Term Debt and Credit Facilities

The Registrants borrow on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under their revolving credit agreements. OGE Energy also borrows under term credit agreements maturing in one year or less, as necessary. As of December 31, 2020, OGE Energy had $95.0 million short-term debt as compared to $112.0 million short-term debt at December 31, 2019. At December 31, 2020, OG&E had $272.0 million in advances to OGE Energy compared to $304.8 million at December 31, 2019.

In April 2020, OGE Energy entered into a $75.0 million floating rate unsecured one-year term credit agreement and borrowed the full $75.0 million, in order to preserve financial flexibility in response to COVID-19. Advances under this agreement were used to refinance existing indebtedness and for working capital and general corporate purposes of OGE Energy. The term credit agreement contained substantially the same covenants as OGE Energy's existing $450.0 million revolving credit agreement. In September 2020, OGE Energy repaid the $75.0 million borrowed under the term credit agreement.



113

The following table presents information regarding the Registrants' revolving credit agreements at December 31, 2020.
Aggregate Amount Weighted-Average
Entity Commitment  Outstanding (A) Interest Rate Expiration
(In millions)
OGE Energy (B) $ 450.0  $ 95.0  0.25  % (D) March 8, 2024 (F)
OG&E (C)(E) 450.0  0.4  1.00  % (D) March 8, 2024 (F)
Total $ 900.0  $ 95.4  0.25  %
(A)Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2020.
(B)This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.  
(C)This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.  
(D)Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.
(E)OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $350.0 million of OGE Energy's revolving credit amount. This agreement has a termination date of March 8, 2024. At December 31, 2020, there were no intercompany borrowings under this agreement. 
(F)In March 2017, the Registrants entered into unsecured five-year revolving credit agreements totaling $900.0 million ($450.0 million for OGE Energy and $450.0 million for OG&E). Each of the revolving credit facilities contained an option, which could be exercised up to two times, to extend the term of the respective facility for an additional year. In March 2018, the Registrants each utilized one of those extensions to extend the maturity of their respective credit facility from March 8, 2022 to March 8, 2023. In January 2021, the Registrants each utilized the second of those extensions to extend the maturity of their respective credit facility from March 8, 2023 to March 8, 2024. Commitments of a single existing lender with respect to $50.0 million of OGE Energy's credit facility, however, were not extended and, unless the non-extending lender is replaced in accordance with the terms of the credit facility, such commitments will expire March 8, 2023. The non-extending lender is not party to the OG&E facility.

In January 2021, the Registrants each entered into an amendment to their revolving credit facilities which gives each of the Registrants the option of extending such commitments for up to two additional one-year periods. In addition, the amendment addresses the establishment of an alternative rate of interest upon the occurrence of certain events related to the phase out of LIBOR.

On February 24, 2021, OGE Energy entered into a commitment letter with Wells Fargo and certain of its affiliates whereby Wells Fargo committed to provide an unsecured term loan facility in the aggregate principal amount of $1.0 billion. While borrowing availability still exists within the Registrants' credit facilities, the $1.0 billion commitment in additional short-term financing is expected to provide additional liquidity to help cover the increased fuel and purchased power costs incurred by OG&E during the February 2021 unprecedented cold weather event. For further discussion, see "Item 9B. Other Information."

The Registrants' credit facilities each have a financial covenant requiring that the respective borrower maintain a maximum debt to capitalization ratio of 65 percent, as defined in each such facility. The Registrants' facilities each also contain covenants which restrict the respective borrower and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of liens and transactions with affiliates. The Registrants' facilities are each subject to acceleration upon the occurrence of any default, including, among others, payment defaults on such facilities, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100.0 million or more in the aggregate, change of control (as defined in each such facility), nonpayment of uninsured judgments in excess of $100.0 million and the occurrence of certain Employee Retirement Income Security Act and bankruptcy events, subject where applicable to specified cure periods.

The Registrants' ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with the Registrants' credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of the Registrants' short-term borrowings, but a reduction in the Registrants' credit ratings would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Registrants to post collateral or letters of credit. 


114

 
OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 2021 and ending December 31, 2022.

13.Retirement Plans and Postretirement Benefit Plans

OGE Energy sponsors defined benefit pension plans, 401(k) savings plans and other postretirement plans covering certain employees of the Registrants.

Pension Plan and Restoration of Retirement Income Plan
 
It is OGE Energy's policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by OGE Energy's actuarial consultants. Such contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future. OGE Energy made a $20.0 million contribution to its Pension Plan in both 2020 and 2019, of which $10.0 million and $5.0 million was attributed to OG&E in 2020 and 2019, respectively. In January 2021, OGE Energy made a $40.0 million contribution to its Pension Plan and has not determined whether it will need to make any additional contributions to the Pension Plan in 2021. Any contribution to the Pension Plan during 2021 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.

In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during the plan year exceed the service cost and interest cost components of the organization's net periodic pension cost. During 2020, 2019 and 2018, the Registrants experienced an increase in both the number of employees electing to retire and the amount of lump sum payments paid to such employees upon retirement, which resulted in the Registrants recording pension plan settlement charges as presented in the Pension Plan net periodic benefit cost table. The pension settlement charges did not require a cash outlay by the Registrants and did not increase total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods.
 
OGE Energy provides a Restoration of Retirement Income Plan to those participants in OGE Energy's Pension Plan whose benefits are subject to certain limitations of the Code. Participants in the Restoration of Retirement Income Plan receive the same benefits that they would have received under OGE Energy's Pension Plan in the absence of limitations imposed by the federal tax laws. The Restoration of Retirement Income Plan is intended to be an unfunded plan.

OG&E's employees participate in OGE Energy's Pension Plan and Restoration of Retirement Income Plan.

Obligations and Funded Status
 
The details of the funded status of OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the balance sheets for 2020 and 2019 are included in the following tables. These amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss (except OG&E's portion, which is recorded as a regulatory asset as discussed in Note 1) in the balance sheets. The amounts in Accumulated Other Comprehensive Loss and those recorded as a regulatory asset represent a net periodic benefit cost to be recognized in the statements of income in future periods. The benefit obligation for OGE Energy's Pension Plan and the Restoration of Retirement Income Plan represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated postretirement benefit obligation. The accumulated postretirement benefit obligation for OGE Energy's Pension Plan and Restoration of Retirement Income Plan differs from the projected benefit obligation in that the former includes no assumption about future compensation levels.



115

OGE Energy OG&E
Pension Plan Restoration of Retirement
Income Plan 		Pension Plan Restoration of Retirement
Income Plan
 December 31 (In millions)
2020 2019 2020 2019 2020 2019 2020 2019
Change in benefit obligation            
Beginning obligations $ 616.1  $ 615.9  $ 10.3  $ 9.6  $ 462.0  $ 453.6  $ 6.1  $ 6.0 
Service cost 13.2  12.9  0.8  0.5  9.2  9.0  0.1  0.2 
Interest cost 17.0  20.7  0.2  0.4  12.6  15.6  0.1  0.2 
Plan settlements (42.8) (83.1) (5.3) (1.2) (33.5) (45.6) (4.5) (0.9)
Plan amendments —  —  —  0.3  —  —  —  — 
Plan curtailments —  —  0.2  —  —  —  —  — 
Special termination benefits 7.6  —  —  —  5.1  —  —  — 
Actuarial losses 57.7  64.3  1.6  0.7  41.0  42.1  1.2  0.6 
Benefits paid (14.2) (14.6) —  —  (12.3) (12.7) —  — 
Ending obligations $ 654.6  $ 616.1  $ 7.8  $ 10.3  $ 484.1  $ 462.0  $ 3.0  $ 6.1 
Change in plans' assets            
Beginning fair value $ 530.3  $ 522.8  $ —  $ —  $ 399.1  $ 387.6  $ —  $ — 
Actual return on plans' assets 77.0  85.2  —  —  57.0  64.8  —  — 
Employer contributions 20.0  20.0  5.3  1.2  10.0  5.0  4.5  0.9 
Plan settlements (42.8) (83.1) (5.3) (1.2) (33.5) (45.6) (4.5) (0.9)
Benefits paid (14.2) (14.6) —  —  (12.3) (12.7) —  — 
Ending fair value $ 570.3  $ 530.3  $ —  $ —  $ 420.3  $ 399.1  $ —  $ — 
Funded status at end of year $ (84.3) $ (85.8) $ (7.8) $ (10.3) $ (63.8) $ (62.9) $ (3.0) $ (6.1)
Accumulated postretirement benefit obligation $ 610.8  $ 563.3  $ 6.9  $ 8.1  $ 454.7  $ 425.8  $ 2.9  $ 4.8 

For the year ended December 31, 2020, Pension Plan actuarial losses were primarily due to movement in the discount rate, special termination benefits due to a voluntary retirement program offered by OGE Energy and more retirements and terminations than expected which are expected to accelerate lump sum payments in 2021. These losses were partially offset by gains from lowering the interest crediting rate and plan mortality assumptions.



116

OGE Energy OG&E
Postretirement Benefit Plans Postretirement Benefit Plans
 December 31 (In millions)
2020 2019 2020 2019
Change in benefit obligation        
Beginning obligations $ 136.5  $ 135.8  $ 104.7  $ 104.8 
Service cost 0.2  0.2  0.2  0.2 
Interest cost 4.2  5.6  3.2  4.3 
Plan curtailments 4.0  —  3.1  — 
Participants' contributions 3.3  4.1  2.4  3.0 
Actuarial losses 7.3  2.9  4.5  2.2 
Benefits paid (11.0) (12.1) (8.6) (9.8)
Ending obligations $ 144.5  $ 136.5  $ 109.5  $ 104.7 
Change in plans' assets        
Beginning fair value $ 47.0  $ 45.3  $ 41.9  $ 40.6 
Actual return on plans' assets 1.2  4.6  1.1  4.0 
Employer contributions 7.1  5.1  5.9  4.1 
Participants' contributions 3.3  4.1  2.4  3.0 
Benefits paid (11.0) (12.1) (8.6) (9.8)
Ending fair value $ 47.6  $ 47.0  $ 42.7  $ 41.9 
Funded status at end of year $ (96.9) $ (89.5) $ (66.8) $ (62.8)

Special termination benefits and curtailment loss for the year ended December 31, 2020 are related to a voluntary retirement program offered by OGE Energy in the fourth quarter of 2020. A curtailment gain or loss is required when the expected future services or benefits in a benefit plan are significantly reduced or eliminated.

Net Periodic Benefit Cost

The following tables present the net periodic benefit cost components, before consideration of capitalized amounts, of OGE Energy's Pension Plan, Restoration of Retirement Income Plan and postretirement benefit plans that are included in the financial statements. Service cost is presented within Other Operation and Maintenance, and the remaining net period benefit cost components as listed in the following tables are presented within Other Net Periodic Benefit Income (Expense) in the statements of income. OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate reviews. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker in the regulatory assets and liabilities table in Note 1 and within Other Net Periodic Benefit Income (Expense) in the statements of income.


117

OGE Energy OG&E
Pension Plan Restoration of Retirement
Income Plan 		Pension Plan Restoration of Retirement
Income Plan
Year Ended December 31 (In millions)
2020 2019 2018 2020 2019 2018 2020 2019 2018 2020 2019 2018
Service cost $ 13.2  $ 12.9  $ 14.9  $ 0.8  $ 0.5  $ 0.4  $ 9.2  $ 9.0  $ 9.8  $ 0.1  $ 0.2  $ 0.2 
Interest cost 17.0  20.7  23.8  0.2  0.4  0.3  12.6  15.6  17.6  0.1  0.2  0.2 
Expected return on plan assets (37.6) (36.1) (44.1) —  —  —  (27.9) (27.6) (33.1) —  —  — 
Amortization of net loss 17.1  17.3  16.2  0.5  0.5  0.7  12.1  12.9  12.1  0.4  0.3  0.5 
Plan curtailments —  —  —  0.2  —  —  —  —  —  —  —  — 
Special termination benefits 7.6  —  —  —  —  —  5.1  —  —  —  —  — 
Amortization of unrecognized prior service cost (A) —  —  —  —  —  0.1  —  —  —  —  —  — 
Settlement cost 14.1  27.6  25.1  2.7  0.5  1.0  11.4  16.4  19.4  2.4  0.5  0.4 
Total net periodic benefit cost 31.4  42.4  35.9  4.4  1.9  2.5  22.5  26.3  25.8  3.0  1.2  1.3 
Less: Amount paid by unconsolidated affiliates (B) 2.0  2.9  2.5  0.1  0.1  0.1 
Plus: Amount allocated from OGE Energy (B) 5.9  4.5  5.7  1.3  0.5  1.2 
Net periodic benefit cost $ 29.4  $ 39.5  $ 33.4  $ 4.3  $ 1.8  $ 2.4  $ 28.4  $ 30.8  $ 31.5  $ 4.3  $ 1.7  $ 2.5 
(A)Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.
(B)"Amount paid by unconsolidated affiliates" is only applicable to OGE Energy. "Amount allocated from OGE Energy" is only applicable to OG&E.

In addition to the net periodic benefit cost amounts recognized, as presented in the table above, for the Pension and Restoration of Retirement Income Plans in 2020, 2019 and 2018, the Registrants recognized the following:
Year Ended December 31 (In millions)
2020 2019 2018
Decrease of pension expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A) $ (13.8) $ (16.1) $ (14.1)
Deferral of pension expense related to pension settlement, curtailment and special termination benefits charges:
Oklahoma jurisdiction (A) $ 21.6  $ 17.9  $ 22.1 
Arkansas jurisdiction (A) $ 2.0  $ 1.7  $ 2.1 
(A) Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.



118

OGE Energy OG&E
Postretirement Benefit Plans Postretirement Benefit Plans
Year Ended December 31 (In millions)
2020 2019 2018 2020 2019 2018
Service cost $ 0.2  $ 0.2  $ 0.3  $ 0.2  $ 0.2  $ 0.2 
Interest cost 4.2  5.6  5.4  3.2  4.3  4.2 
Expected return on plan assets (1.8) (1.9) (2.0) (1.7) (1.7) (1.8)
Amortization of net loss 2.0  2.0  3.8  2.1  2.1  3.8 
Plan curtailments 1.5  —  —  1.3  —  — 
Amortization of unrecognized prior service cost (A) (8.4) (8.4) (8.4) (6.1) (6.1) (6.1)
Total net periodic benefit cost (2.3) (2.5) (0.9) (1.0) (1.2) 0.3 
Less: Amount paid by unconsolidated affiliates (B) (0.7) (0.6) (0.5)
Plus: Amount allocated from OGE Energy (B) (0.5) (0.6) (0.7)
Net periodic benefit cost $ (1.6) $ (1.9) $ (0.4) $ (1.5) $ (1.8) $ (0.4)
(A) Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.
(B) "Amount paid by unconsolidated affiliates" is only applicable to OGE Energy. "Amount allocated from OGE Energy" is only applicable to OG&E.

In addition to the net periodic benefit income amounts recognized, as presented in the table above, for the postretirement benefit plans in 2020, 2019 and 2018, the Registrants recognized the following:
Year Ended December 31 (In millions)
2020 2019 2018
Increase of postretirement expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A) $ 0.2  $ 1.0  $ 4.4 
Deferral of postretirement expense related to postretirement plan curtailment charges:
Oklahoma jurisdiction (A) $ 1.4  $ —  $ — 
Arkansas jurisdiction (A) $ 0.1  $ —  $ — 
(A) Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.

OGE Energy OG&E
(In millions) 2020 2019 2018 2020 2019 2018
Capitalized portion of net periodic pension benefit cost $ 3.8  $ 3.6  $ 3.8  $ 3.1  $ 3.0  $ 3.2 
Capitalized portion of net periodic postretirement benefit cost $ 0.2  $ 0.2  $ 0.2  $ 0.1  $ 0.1  $ 0.1 


119

Rate Assumptions
Pension Plan and
Restoration of Retirement Income Plan 		Postretirement
Benefit Plans
Year Ended December 31 2020 2019 2018 2020 2019 2018
Assumptions to determine benefit obligations:
Discount rate 2.30  % 3.15  % 4.20  % 2.45  % 3.25  % 4.30  %
Rate of compensation increase 4.20  % 4.20  % 4.20  % N/A N/A N/A
Interest crediting rate 3.50  % 4.00  % 4.00  % N/A N/A N/A
Assumptions to determine net periodic benefit cost:
Discount rate 2.88  % 3.63  % 3.73  % 3.25  % 4.30  % 3.70  %
Expected return on plan assets 7.50  % 7.50  % 7.50  % 4.00  % 4.00  % 4.00  %
Rate of compensation increase 4.20  % 4.20  % 4.20  % N/A N/A N/A
Interest crediting rate 4.00  % 4.00  % 4.00  % N/A N/A N/A
N/A - not applicable
 
The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The discount rate used to determine net benefit cost for the current year is the same discount rate used to determine the benefit obligation as of the previous year's balance sheet date, unless a plan settlement occurs during the current year that requires an updated discount rate for net periodic cost measurement. For 2020 and 2019, the Pension Plan discount rates used to determine net periodic benefit cost are disclosed on a weighted-average basis.

The overall expected rate of return on plan assets assumption is used in determining net periodic benefit cost due to recent returns on OGE Energy's long-term investment portfolio. The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to be invested for the purpose of providing benefits specified by the Pension Plan or postretirement benefit plans. This assumption is reexamined at least annually and updated as necessary. The rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans' current and expected asset allocation.

The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans. Future health care cost trend rates are assumed to be 6.75 percent in 2021 with the rates trending downward to 4.50 percent by 2030. 

Pension Plan

Pension Plan Investments, Policies and Strategies
 
The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability-driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The following table presents the targeted fixed income and equity allocations at different funded status levels.
Projected Benefit Obligation Funded Status Thresholds <90% 95% 100% 105% 110% 115% 120%
Fixed income 50% 58% 65% 73% 80% 85% 90%
Equity 50% 42% 35% 27% 20% 15% 10%
Total 100% 100% 100% 100% 100% 100% 100%



120

Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the following table.
        Asset Class Target Allocation Minimum Maximum
Domestic Large Cap Equity 40% 35% 60%
Domestic Mid-Cap Equity 15% 5% 25%
Domestic Small-Cap Equity 25% 5% 30%
International Equity 20% 10% 30%
 
OGE Energy has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of the Registrants' members and OGE Energy's Investment Committee. The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for each investment manager's respective portfolio. 

The portfolio is rebalanced at least on an annual basis to bring the asset allocations of various managers in line with the target asset allocation listed above. More frequent rebalancing may occur if there are dramatic price movements in the financial markets which may cause the trust's exposure to any asset class to exceed or fall below the established allowable guidelines.

To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however, expected that performance goals will be met over a full market cycle, normally defined as a three- to five-year period. Analysis of performance is within the context of the prevailing investment environment and the advisors' investment style. The goal of the trust is to provide a rate of return consistently from three percent to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years. Each investment manager is expected to outperform its respective benchmark. 

The following table presents a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against and the focus of the asset class.
Asset Class Comparative Benchmark(s) Focus of Asset Class
Active Duration Fixed Income (A)(B) Bloomberg Barclays Aggregate
l Maximize risk-adjusted performance while
    providing long bond exposure managed according
    to the manager's forecast on interest rates.
l All invested assets must reach at or above Baa3 or
    BBB- investment grade.
l Limited five percent exposure to any single issuer,
    except the U.S. Government or affiliates.
Long Duration Fixed Income (A)(B) Duration blended Barclays Long Government/Credit & Barclays Universal
l Maximize risk-adjusted performance.
l At least 75 percent of invested assets much reach at
    or above Baaa3 or BBB- investment grade.
l Limited five percent exposure to any single issuer,
    except the U.S. Government or affiliates.
l May invest up to 10 percent of the market value in
    convertible bonds as long as quality guidelines are
    met.
l May invest up to 15 percent of the market value in
    private placement, including 144A securities with
    or without registration rights and allow for futures
    to be traded in the portfolio.
Equity Index (B)(C) Standard & Poor's 500 Index
l Focus on replicating the performance of the S&P
    500 Index.
Mid-Cap Equity (B)(C) Russell Midcap Index
Russell Midcap Value Index
l Focus on undervalued stocks expected to earn
    average return and pay out higher than average
    dividends.
l Invest in companies with market capitalizations
    lower than average company on public exchanges:
l Price/earnings ratio at or near referenced
    index;
l Small dividend yield and return on equity
    at or near referenced index; and
l Earnings per share growth rate at or near
    referenced index.
Small-Cap Equity (B)(C) Russell 2000 Index
Russell 2000 Value Index


121

International Equity (D) Morgan Stanley Capital International ACWI ex-U.S.
l Invest in non-dollar denominated equity securities.
l Diversify the overall trust investments.
(A)Investment grades are by Moody's Investors Service, S&P Global Ratings or Fitch Ratings.
(B)The purchase of any of OGE Energy's equity, debt or other securities is prohibited.
(C)No more than five percent can be invested in any one stock at the time of purchase and no more than 10 percent after accounting for price appreciation. Options or financial futures may not be purchased unless prior approval from OGE Energy's Investment Committee is received. The purchase of securities on margin, securities lending, private placement purchases and venture capital purchases are prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.
(D)The manager of this asset class is required to operate under certain restrictions including regional constraints, diversification requirements and percentage of U.S. securities. All securities are freely traded on a recognized stock exchange, and there are no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares).

Pension Plan Investments
 
The following tables present the Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 2020 and 2019. There were no Level 3 investments held by the Pension Plan at December 31, 2020 and 2019. 
(In millions) December 31, 2020 Level 1 Level 2 Net Asset Value (A)
Common stocks $ 252.3  $ 252.3  $ —  $ — 
U.S. Treasury notes and bonds (B) 134.3  134.3  —  — 
Mortgage- and asset-backed securities 29.3  —  29.3  — 
Corporate fixed income and other securities 116.6  —  116.6  — 
Commingled fund (C) 25.4  —  —  25.4 
Foreign government bonds 4.6  —  4.6  — 
U.S. municipal bonds 1.8  —  1.8  — 
Money market fund 8.8  —  —  8.8 
Mutual fund 9.2  9.2  —  — 
Preferred stocks 0.6  0.6  —  — 
U.S. Treasury futures:
Cash collateral 0.7  0.7  —  — 
Forward contracts:
Receivable (foreign currency) 0.1  —  0.1  — 
Total Pension Plan investments 583.7  $ 397.1  $ 152.4  $ 34.2 
Receivable from broker for securities sold 0.2     
Interest and dividends receivable 2.2     
Payable to broker for securities purchased (15.8)    
Total OGE Energy Pension Plan assets $ 570.3     
Pension Plan investments attributable to affiliates (150.0)
Total OG&E Pension Plan assets $ 420.3 
(A)GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.
(B)This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher.
(C)This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.



122

(In millions) December 31, 2019 Level 1 Level 2 Net Asset Value (A)
Common stocks $ 202.0  $ 202.0  $ —  $ — 
U.S. Treasury notes and bonds (B) 134.8  134.8  —  — 
Mortgage- and asset-backed securities 45.8  —  45.8  — 
Corporate fixed income and other securities 130.5  —  130.5  — 
Commingled fund (C) 23.9  —  —  23.9 
Foreign government bonds 3.0  —  3.0  — 
U.S. municipal bonds 1.1  —  1.1  — 
Money market fund 2.4  —  —  2.4 
Mutual fund 7.5  7.5  —  — 
Preferred stocks 0.7  0.7  —  — 
Futures:
U.S. Treasury futures (receivable) 22.9  —  22.9  — 
U.S. Treasury futures (payable) (10.9) —  (10.9) — 
Cash collateral 0.6  0.6  —  — 
Forward contracts:
Receivable (foreign currency) 0.1  —  0.1  — 
Total Pension Plan investments 564.4  $ 345.6  $ 192.5  $ 26.3 
Interest and dividends receivable 2.4     
Payable to broker for securities purchased (36.5)    
Total OGE Energy Pension Plan assets $ 530.3     
Pension Plan investments attributable to affiliates (131.2)
Total OG&E Pension Plan assets $ 399.1 
(A)GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.
(B)This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher.
(C)This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.
 
As defined in the fair value hierarchy, Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible by the Pension Plan at the measurement date. Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the Plan's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).



123

Expected Benefit Payments

The following table presents the benefit payments the Registrants expect to pay related to the Pension Plan and Restoration of Retirement Income Plan. These expected benefits are based on the same assumptions used to measure OGE Energy's benefit obligation at the end of the year and include benefits attributable to estimated future employee service. 
 
(In millions)
OGE Energy OG&E
2021 $ 164.2  $ 123.9 
2022 $ 43.3  $ 33.1 
2023 $ 42.5  $ 31.9 
2024 $ 44.2  $ 32.3 
2025 $ 41.1  $ 29.3 
After 2025 $ 203.6  $ 141.1 

Postretirement Benefit Plans

In addition to providing pension benefits, OGE Energy provides certain medical and life insurance benefits for eligible retired members. Regular, full-time, active employees hired prior to February 1, 2000 whose age and years of credited service total or exceed 80 or have attained at least age 55 with 10 or more years of service at the time of retirement are entitled to postretirement medical benefits, while employees hired on or after February 1, 2000 are not entitled to postretirement medical benefits. Eligible retirees must contribute such amount as OGE Energy specifies from time to time toward the cost of coverage for postretirement benefits. The benefits are subject to deductibles, co-payment provisions and other limitations. OG&E charges postretirement benefit costs to expense and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.

OGE Energy's contribution to the medical costs for pre-65 aged eligible retirees are fixed at the 2011 level, and OGE Energy covers future annual medical inflationary cost increases up to five percent. Increases in excess of five percent annually are covered by the pre-65 aged retiree in the form of premium increases. OGE Energy provides Medicare-eligible retirees and their Medicare-eligible spouses an annual fixed contribution to an OGE Energy-sponsored health reimbursement arrangement. Medicare-eligible retirees are able to purchase individual insurance policies supplemental to Medicare through a third-party administrator and use their health reimbursement arrangement funds for reimbursement of medical premiums and other eligible medical expenses.



124

Postretirement Plans Investments
 
The following tables present the postretirement benefit plans' investments that are measured at fair value on a recurring basis at December 31, 2020 and 2019. There were no Level 2 investments held by the postretirement benefit plans at December 31, 2020 and 2019.
(In millions) December 31, 2020 Level 1 Level 3
Group retiree medical insurance contract $ 33.4  $ —  $ 33.4 
Mutual fund 10.8  10.8  — 
Money market fund 3.4  3.4  — 
Total OGE Energy plan investments $ 47.6  $ 14.2  $ 33.4 
Plan investments attributable to affiliates (4.9)
Total OG&E plan investments $ 42.7 

(In millions) December 31, 2019 Level 1 Level 3
Group retiree medical insurance contract $ 34.8  $ —  $ 34.8 
Mutual funds 10.9  10.9  — 
Money market fund 1.2  1.2  — 
Total OGE Energy plan investments $ 46.9  $ 12.1  $ 34.8 
Plan investments attributable to affiliates (5.0)
Total OG&E plan investments $ 41.9 

The group retiree medical insurance contract invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities. The unobservable input included in the valuation of the contract includes the approach for determining the allocation of the postretirement benefit plans' pro-rata share of the total assets in the contract.
 
The following table presents a reconciliation of the postretirement benefit plans' investments that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).
Year Ended December 31 (In millions)
2020
Group retiree medical insurance contract:
Beginning balance $ 34.8 
Claims paid (3.7)
Investment fees (0.1)
Interest income 0.8 
Net unrealized gains related to instruments held at the reporting date 0.6 
Dividend income 0.6 
Realized gains 0.4 
Ending balance $ 33.4 
 


125

Medicare Prescription Drug, Improvement and Modernization Act of 2003
 
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 expanded coverage for prescription drugs. The following table presents the gross benefit payments the Registrants expect to pay related to the postretirement benefit plans, including prescription drug benefits.
(In millions) OGE Energy OG&E
2021 $ 11.9  $ 9.4 
2022 $ 11.8  $ 9.3 
2023 $ 11.4  $ 8.9 
2024 $ 10.0  $ 7.7 
2025 $ 9.5  $ 7.3 
After 2025 $ 40.9  $ 31.0 

Post-Employment Benefit Plan
 
Disabled employees receiving benefits from OGE Energy's Group Long-Term Disability Plan are entitled to continue participating in OGE Energy's Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in the Group Long-Term Disability Plan and their dependents, as defined in OGE Energy's Medical Plan.
 
The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from OGE Energy's Group Long-Term Disability Plan due to death, recovery from disability or eligibility for retiree medical benefits. OGE Energy's post-employment benefit obligation was $2.2 million and $2.1 million at December 31, 2020 and 2019, respectively, of which $1.8 million and $1.7 million, respectively, was OG&E's portion of the obligation.
 
401(k) Plan
 
OGE Energy provides a 401(k) Plan, and each regular full-time employee of OGE Energy or a participating affiliate is eligible to participate in the 401(k) Plan immediately upon hire. All other employees of OGE Energy or a participating affiliate are eligible to become participants in the 401(k) Plan after completing one year of service as defined in the 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have reached age 50 before the close of a year are allowed to make additional contributions referred to as "Catch-Up Contributions," subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof, (ii) a contribution made on a non-Roth after-tax basis or (iii) a Roth contribution. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have their future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election. For employees hired or rehired on or after December 1, 2009, OGE Energy contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation.

No OGE Energy contributions are made with respect to a participant's Catch-Up Contributions, rollover contributions or with respect to a participant's contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Once made, OGE Energy's contribution may be directed to any available investment option in the 401(k) Plan. OGE Energy match contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their OGE Energy contribution account and become fully vested on completing three years of service. In addition, participants fully vest when they are eligible for normal or early retirement under the Pension Plan requirements, in the event of their termination due to death or permanent disability or upon attainment of age 65 while employed by OGE Energy or its affiliates. OGE Energy contributed $18.2 million, $14.4 million and $13.2 million in 2020, 2019 and 2018, respectively, to the 401(k) Plan, of which $14.3 million, $11.0 million and $9.8 million, respectively, related to OG&E.


126

 
Deferred Compensation Plan
 
OGE Energy provides a nonqualified deferred compensation plan which is intended to be an unfunded plan. The plan's primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of OGE Energy's Board of Directors and to supplement such employees' 401(k) Plan contributions as well as offering this plan to be competitive in the marketplace.
 
Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of annual bonus awards or (ii) eligible employees may elect a deferral percentage of base salary and bonus awards based on the deferral percentage elected for a year under the 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) Plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors' meeting fees and annual retainers. OGE Energy matches employee (but not non-employee director) deferrals to make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on prior participant elections, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after three years or, if earlier, on retirement, disability, death, a change in control of OGE Energy or termination of the plan. Deferrals, plus any OGE Energy match, are credited to a recordkeeping account in the participant's name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. In 2020, those investment options included an OGE Energy Common Stock fund, whose value was determined based on the stock price of OGE Energy's Common Stock. OGE Energy accounts for the contributions related to its executive officers in this plan as Accrued Benefit Obligations and accounts for the contributions related to OGE Energy's directors in this plan as Other Deferred Credits and Other Liabilities in the balance sheets. The investment associated with these contributions is accounted for as Other Property and Investments in the balance sheets. The appreciation of these investments is accounted for as Other Income, and the increase in the liability under the plan is accounted for as Other Expense in the statements of income.
  
Supplemental Executive Retirement Plan

OGE Energy provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee of OGE Energy's Board of Directors who may not otherwise qualify for a sufficient level of benefits under OGE Energy's Pension Plan and Restoration of Retirement Income Plan. The supplemental executive retirement plan is intended to be an unfunded plan and not subject to the benefit limitations of the Code. For the actuarial equivalence calculations, the supplemental executive retirement plan provides that (i) mortality rates shall be based on the unisex mortality table issued under Internal Revenue Service Notice 2018-02 for purposes of determining the minimum present value under Code Section 417(e)(3) for distributions with annuity starting dates that occur during stability periods beginning in the 2019 calendar year and (ii) the interest rate shall be five percent.


127

14.Report of Business Segments

OGE Energy reports its operations in two business segments: (i) the electric utility segment, which is engaged in the generation, transmission, distribution and sale of electric energy and (ii) natural gas midstream operations segment. Other operations primarily includes the operations of the holding company. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. The following tables present the results of OGE Energy's business segments for the years ended December 31, 2020, 2019 and 2018.
2020 Electric Utility Natural Gas Midstream Operations Other
Operations 		Eliminations Total
(In millions)          
Operating revenues $ 2,122.3  $ —  $ —  $ —  $ 2,122.3 
Cost of sales 644.6  —  —  —  644.6 
Other operation and maintenance 464.4  1.7  (3.3) —  462.8 
Depreciation and amortization 391.3  —  —  —  391.3 
Taxes other than income 97.2  0.4  3.8  —  101.4 
Operating income (loss) 524.8  (2.1) (0.5) —  522.2 
Equity in losses of unconsolidated affiliates (A) —  (668.0) —  —  (668.0)
Other income (expense) 4.1  (2.9) 3.6  (1.6) 3.2 
Interest expense 154.8  —  5.3  (1.6) 158.5 
Income tax expense (benefit) 34.7  (158.0) (4.1) —  (127.4)
Net income (loss) $ 339.4  $ (515.0) $ 1.9  $ —  $ (173.7)
Investment in unconsolidated affiliates $ —  $ 374.3  $ 23.1  $ —  $ 397.4 
Total assets $ 10,489.0  $ 378.1  $ 116.4  $ (264.7) $ 10,718.8 
Capital expenditures $ 650.5  $ —  $ —  $ —  $ 650.5 
(A) In March 2020, OGE Energy recorded a $780.0 million impairment on its investment in Enable, as further discussed in Notes 5 and 7.

2019 Electric Utility Natural Gas Midstream Operations Other
Operations 		Eliminations Total
(In millions)          
Operating revenues $ 2,231.6  $ —  $ —  $ —  $ 2,231.6 
Cost of sales 786.9  —  —  —  786.9 
Other operation and maintenance 492.5  2.8  (3.5) —  491.8 
Depreciation and amortization 355.0  —  —  —  355.0 
Taxes other than income 89.5  0.4  3.7  —  93.6 
Operating income (loss) 507.7  (3.2) (0.2) —  504.3 
Equity in earnings of unconsolidated affiliates —  113.9  —  —  113.9 
Other income (expense) 3.1  (8.6) 2.2  (3.6) (6.9)
Interest expense 140.5  —  11.0  (3.6) 147.9 
Income tax expense (benefit) 20.1  20.7  (11.0) —  29.8 
Net income $ 350.2  $ 81.4  $ 2.0  $ —  $ 433.6 
Investment in unconsolidated affiliates $ —  $ 1,132.9  $ 18.6  $ —  $ 1,151.5 
Total assets $ 10,076.6  $ 1,135.4  $ 107.0  $ (294.7) $ 11,024.3 
Capital expenditures $ 635.5  $ —  $ —  $ —  $ 635.5 




128

2018 Electric Utility Natural Gas Midstream Operations Other
Operations 		Eliminations Total
(In millions)
Operating revenues $ 2,270.3  $ —  $ —  $ —  $ 2,270.3 
Cost of sales 892.5  —  —  —  892.5 
Other operation and maintenance 473.8  1.4  (0.6) —  474.6 
Depreciation and amortization 321.6  —  —  —  321.6 
Taxes other than income 88.2  0.6  3.2  —  92.0 
Operating income (loss) 494.2  (2.0) (2.6) —  489.6 
Equity in earnings of unconsolidated affiliates —  152.8  —  —  152.8 
Other income (expense) 25.6  (4.9) (3.4) (6.0) 11.3 
Interest expense 151.8  —  10.2  (6.0) 156.0 
Income tax expense (benefit) 40.0  37.1  (4.9) —  72.2 
Net income (loss) $ 328.0  $ 108.8  $ (11.3) $ —  $ 425.5 
Investment in unconsolidated affiliates $ —  $ 1,166.6  $ 10.9  $ —  $ 1,177.5 
Total assets $ 9,704.5  $ 1,169.8  $ 184.8  $ (310.5) $ 10,748.6 
Capital expenditures $ 573.6  $ —  $ —  $ —  $ 573.6 

15.Commitments and Contingencies
 
Public Utility Regulatory Policy Act of 1978

OG&E had QF contracts with AES-Shady Point, Inc. and Oklahoma Cogeneration LLC, which expired in January and August 2019, respectively. For the 320 MW AES-Shady Point, Inc. QF contract and the 120 MW Oklahoma Cogeneration LLC QF contract, OG&E purchased 100 percent of the electricity generated by the qualified cogeneration facilities. In 2019, OG&E received approval from the OCC and APSC to acquire the plants from AES-Shady Point, Inc. and Oklahoma Cogeneration LLC.

For the years ended December 31, 2019 and 2018, OG&E made total payments to cogenerators of $14.7 million and $112.4 million, respectively, of which $7.4 million and $60.0 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Registrants' statements of income as Cost of Sales.

Purchase Obligations and Commitments

The following table presents the Registrants' future purchase obligations and commitments estimated for the next five years. 
(In millions) 2021 2022 2023 2024 2025 Total
Purchase obligations and commitments:            
Minimum purchase commitments $ 72.5  $ 50.4  $ 50.4  $ 36.7  $ 25.9  $ 235.9 
Expected wind purchase commitments 55.2  55.6  56.0  56.6  56.9  280.3 
Long-term service agreement commitments 2.4  2.4  7.9  35.1  31.2  79.0 
Total purchase obligations and commitments $ 130.1  $ 108.4  $ 114.3  $ 128.4  $ 114.0  $ 595.2 

OG&E Minimum Purchase Commitments
 
OG&E has coal contracts for purchases through June 30, 2021, whereby OG&E has the right but not the obligation to purchase a defined quantity of coal. OG&E may also purchase coal through spot purchases on an as-needed basis. As a participant in the SPP Integrated Marketplace, OG&E purchases its natural gas supply through short-term agreements. OG&E relies on a combination of natural gas base load agreements and call agreements, whereby OG&E has the right but not the obligation to purchase a defined quantity of natural gas, combined with day and intra-day purchases to meet the demands of the SPP Integrated Marketplace.


129


OG&E has natural gas transportation service contracts with Enable, ONEOK, Inc. and Southern Star. The contracts with Enable end in May 2024 and December 2038; the contracts with ONEOK, Inc. end in March 2024 and August 2037; and the contract with Southern Star ends in June 2024. These transportation contracts grant Enable, ONEOK, Inc. and Southern Star the responsibility of delivering natural gas to OG&E's generating facilities.

OG&E Wind Purchase Commitments
 
The following table presents OG&E's wind power purchase contracts.
Company Location Original Term of Contract Expiration of Contract MWs
CPV Keenan Woodward County, OK 20 years 2030 152.0
Edison Mission Energy Dewey County, OK 20 years 2031 130.0
NextEra Energy Blackwell, OK 20 years 2032 60.0

The following table presents a summary of OG&E's wind power purchases for the years ended December 31, 2020, 2019 and 2018. 
Year Ended December 31 (In millions)
2020 2019 2018
CPV Keenan $ 27.5  $ 27.2  $ 27.0 
Edison Mission Energy 22.8  23.1  21.7 
NextEra Energy 7.0  7.4  6.8 
FPL Energy (A) —  —  2.1 
Total wind power purchased $ 57.3  $ 57.7  $ 57.6 
(A)OG&E's purchased power contract with FPL Energy for 50 MWs expired in 2018.

OG&E Long-Term Service Agreement Commitments
 
OG&E has a long-term parts and service maintenance contract for the upkeep of the McClain Plant. In May 2013, a new contract was signed that is expected to run for the earlier of 128,000 factored-fired hours or 4,800 factored-fired starts. In December 2015, the McClain Long-Term Service Agreement was amended to define the terms and conditions for the exchange of spare rotors between OG&E and General Electric International, Inc. Based on historical usage and current expectations for future usage, this contract is expected to run until 2033. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used.
 
OG&E has a long-term parts and service maintenance contract for the upkeep of the Redbud Plant. In March 2013, the contract was amended to extend the contract coverage for an additional 24,000 factored-fired hours resulting in a maximum of the earlier of 144,000 factored-fired hours or 4,500 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2030. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.

Environmental Laws and Regulations
 
The activities of the Registrants are subject to numerous stringent and complex federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact the Registrants' business activities in many ways, including the handling or disposal of waste material, planning for future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions or pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of the Registrants' operations are in substantial compliance with current federal, state and local environmental standards.

Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.



130

CO2 Emission Limits for Existing Generating Units

On January 19, 2021, the U.S. Court of Appeals vacated the EPA's latest effort to adopt CO2 emissions standards for existing coal-fired electric generating units, and the court remanded the matter to the EPA for further consideration. The decision was based on the court's conclusion that the Clean Air Act does not require the EPA to limit the standards to measures that can be applied at and to an existing unit. The time for seeking further judicial review of the decision does not expire until June 18, 2021, and the EPA has not announced how it plans to respond to the decision. The ultimate timing and impact of these standards on OG&E's operations cannot be determined with certainty at this time, although a requirement for significant reduction of CO2 emissions from existing fossil-fuel-fired power plants ultimately could result in significant additional compliance costs that would affect the Registrants' future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

Other
 
In the normal course of business, the Registrants are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion, the Registrants have incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in the financial statements. At the present time, based on currently available information, the Registrants believe that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to their financial statements and would not have a material adverse effect on their financial position, results of operations or cash flows. 

16.Rate Matters and Regulation
 
Regulation and Rates

OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations. In 2020, 86 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and six percent to the FERC.

The OCC and the APSC require that, among other things, (i) OGE Energy permits the OCC and the APSC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E; (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers; and (iii) OGE Energy refrain from pledging OG&E assets or income for affiliate transactions. In addition, the FERC has access to the books and records of OGE Energy and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.

Completed Regulatory Matters

APSC Proceedings

Arkansas 2019 Formula Rate Plan Filing

OG&E filed its second evaluation report under its Formula Rate Plan in October 2019. On February 28, 2020, the APSC approved a settlement agreement among OG&E, the General Staff of the APSC and the Office of the Arkansas Attorney General providing for a $5.2 million revenue increase, with rates effective April 1, 2020. The settling parties agreed that the Series I grid modernization projects are prudent in both action and cost and that the Series II grid modernization projects are prudent in action only and the determination of prudence of costs will be reserved until the actual historical costs are reviewed. The settling parties also agreed that OG&E will no longer use projections for the remaining initial term or extension of its current Formula Rate Plan and that all costs will be included for recovery for the first time in the historical year.

Order Regarding COVID-19

On April 10, 2020, the APSC issued Order No. 1 related to COVID-19 and the provision of safe, adequate and reliable utility service at just and reasonable rates. Among other things, the APSC ordered the suspension of customer disconnects for non-payment during the pendency of the Arkansas Governor's emergency declaration or until the directive is rescinded by the


131

APSC, neither of which have occurred yet, although the APSC has requested comments as to whether the moratorium should be lifted. The order encourages companies to provide reasonable payment arrangements once the suspension is lifted. The APSC also authorized utilities to establish regulatory assets to record costs resulting from the suspension of disconnections. These regulatory assets will be reviewed in future proceedings for reasonableness. The APSC ordered the General Staff of the APSC to consult with utilities to create a quarterly report to be used to report the costs incurred and saved that have been booked to the regulatory asset. OG&E is monitoring the regulatory activity regarding COVID-19 at the APSC and will consider the request for additional regulatory action by the APSC as needed.

On May 1, 2020, OG&E filed a Request for Additional Actions and Tariff Deviation seeking relief from the Arkansas General Service Rules and OG&E's Terms and Conditions under the tariff, in order to allow for: more flexible deferred payment agreements for all customer classes, suspension of increased deposits due to non-payment and suspension of the removal of customers from certain billing and extended due date plans for late payments. In addition, OG&E requested that incremental expenses, such as additional personal protective equipment, increased sanitation efforts at facilities, implementing health-screening processes and securing temporary facilities for potential sequestration of critical operation personnel, be tracked in a regulatory asset. OG&E noted that all possible cost categories are not known currently and reserved the right to file subsequent requests as needed.

On May 27, 2020, the APSC issued an order approving OG&E's request to deviate from the specified terms in the Arkansas General Service Rules and OG&E's Terms and Conditions to allow deferred payment arrangements to be offered to all customer classes and have more flexible payment arrangements. OG&E is authorized to record the expenses requested in its regulatory asset to defer and seek future recovery. The APSC found that because each utility has different cost recovery mechanisms and the magnitude of the utilities' expenses are unknown at this time, the APSC finds that it is premature to decide the exact recovery mechanism for any utility for COVID-19 related costs.

Environmental Compliance Plan Rider

In May 2019, OG&E filed an environmental compliance plan rider in Arkansas to recover its investment for the environmentally mandated costs associated with the Sooner Dry Scrubbers project and the conversion of Muskogee Units 4 and 5 to natural gas. The filing initiated an interim surcharge, subject to refund, that began with the first billing cycle of June 2019. OG&E had been reserving the amounts collected through the interim surcharge, pending APSC approval of OG&E's filing. A hearing on the merits was held in December 2019. Parties submitted additional briefs to the APSC in March 2020, which were requested due to certain intervenors questioning whether a company can utilize an environmental compliance plan rider while also being regulated under a formula rate plan. The APSC Staff concurred with OG&E that the rider may run concurrently with a formula rate plan, and the Arkansas Attorney General and other intervenors were in opposition. On July 31, 2020, OG&E's request to recover its investment for these environmentally mandated costs through the interim surcharge was not approved, as the APSC indicated OG&E could otherwise recover this investment, such as through the Formula Rate Plan Rider. As of December 31, 2020, OG&E has returned $5.3 million to customers that had been reserved for refund and has included those costs for recovery in its 2020 Formula Rate Plan filing.

Arkansas Solar

On July 29, 2020, OG&E submitted its application for a Certificate of Public Convenience and Necessity to construct and operate a five MW solar generation facility near Branch, Arkansas. On September 30, 2020, the parties reached a unanimous settlement agreement relating to the filing, and on November 6, 2020, the APSC issued a final order approving the settlement agreement. The terms of the settlement are as follows: (i) parties agree that OG&E has complied with Arkansas law and rules of practice and procedure and recommend granting a Certificate of Public Convenience and Necessity for the construction, ownership and operation of the project and associated tariffs; (ii) OG&E agrees that it would not seek cost recovery until its next general rate review or Formula Rate Plan filing; (iii) OG&E agrees to keep detailed records of final cost, for review at such time that cost recovery is sought, including all cost variance estimates, whereby a determination of prudency of cost may be made; and (iv) OG&E agrees to reserve 50 percent of the total expected energy produced for residential customers for the first 90 days of the program's initial subscription period.

Net Metering Order

On June 1, 2020, the APSC revised its net-metering rules. The revised rules retained 1:1 full credit for net excess generation of residential customers and commercial customers up to 1 MW without demand charges. For larger commercial customers, 1 MW to 20 MW, the APSC found that some cost shifting to non-net-metering customers may occur. While the rules retain 1:1 full credit for net excess generation, they allow for a grid charge. The grid charge is initially set at zero; however, a utility may request approval to revise the grid charge based on evidence that an unreasonable cost shift to non-net-metering customers is occurring. OG&E does not currently have a significant number of net-metering customers in Arkansas.


132

OG&E amended its existing net-metering tariffs considering the new rules. The APSC approved OG&E's revised tariffs on February 5, 2021.

OCC Proceedings

OCC Public Utility Division Motion Regarding COVID-19

On April 28, 2020, the Director of the Public Utility Division filed an application requesting an order from the OCC authorizing action in response to COVID-19. The application requested that the OCC authorize the State's utilities to record as a regulatory asset increased bad debt expenses, costs associated with expanded payment plans, waived fees and incremental expenses that are directly related to the suspension of or delay in disconnection of service beginning March 15, 2020, which coincides with the issuance of the Oklahoma Governor's emergency declaration. The application also requested that the OCC allow utilities to defer additional expenses associated with ensuring the continuity of utility service, such as additional personal protective equipment, increased sanitation efforts at facilities, implementing heath-screening processes and securing temporary facilities for potential sequestration of critical operation personnel. The application asked the OCC to consider in future proceedings whether each utility's request for recovery of these regulatory assets is reasonable and necessary and to consider issues such as the incremental bad debt experienced over normal periods, the appropriate period of recovery for any approved amount of regulatory asset, any amount of carrying costs and other related matters.

On May 7, 2020, the OCC ordered that each utility is authorized to record as a regulatory asset any increased bad debt expense, cost associated with expanded payment plans, waived fees and incremental expenses that are directly related to the suspension of or delay in disconnection of service beginning March 15, 2020 until September 2020, unless otherwise ordered by the OCC. The OCC will consider in future proceedings whether each utility's request for recovery of these regulatory assets is reasonable and necessary. The OCC will also consider issues such as the incremental bad debt experienced over normal periods, appropriate period of recovery for any approved amount of regulatory assets, any amounts of carrying costs thereon and other related matters. The OCC also authorized utilities to defer expenses associated with ensuring continuity of service and protecting utility personnel, customers and the general public.

2019 Oklahoma Fuel Prudency

On June 16, 2020, the Public Utility Division Staff filed their application initiating the review of the 2019 fuel adjustment clause and prudence review. On December 30, 2020, the OCC issued a final order finding OG&E's 2019 fuel costs and related practices prudent.

Oklahoma Grid Enhancement Plan

On February 24, 2020, OG&E filed an application with the OCC for approval of a mechanism that allows for interim recovery of the costs associated with its grid enhancement plan. The plan includes approximately $800.0 million of strategic, data-driven investments, over five years, covering grid resiliency, grid automation, communication systems and technology platforms and applications. On May 19, 2020, the OCC temporarily suspended the procedural schedule in light of various conditions related to the COVID-19 pandemic and the uncertainty surrounding the method and date in which the hearing on the merits may occur. On July 9, 2020, a prehearing conference was held before the Administrative Law Judge to establish a procedural schedule and lift the stay ordered on May 19, 2020. On July 23, 2020, the OCC issued an order approving the amended procedural schedule and thereby lifting the stay.

On October 5, 2020, OG&E filed a Joint Stipulation and Settlement Agreement that included the following key terms: (i) cost recovery through a rider mechanism will be limited to projects placed in service in 2020 and 2021, capped at a revenue requirement of $7.0 million annually and only include communication, automation and technology systems projects; (ii) no operation and maintenance expense will be included in the rider mechanism; (iii) the rider mechanism will terminate by the issuance of a final order in OG&E's next general rate review or October 31, 2022, whichever occurs first; (iv) the rider mechanism rate of return will be capped at OG&E's current cost of capital; and (v) all cost recovery is subject to true-up and refund in OG&E's next general rate review. On November 5, 2020, the OCC issued a final order approving the Joint Stipulation and Settlement Agreement. In compliance with the final order, OG&E submitted a final list of projects for inclusion in the rider mechanism on December 5, 2020 and a revised rider mechanism for initial recovery of costs on December 15, 2020. The rider mechanism became effective on February 1, 2021.

Any capital investment falling outside the criteria of the rider mechanism will be included in OG&E's next general rate review for recovery.



133

Pending Regulatory Matters

Various proceedings pending before state or federal regulatory agencies are described below. Unless stated otherwise, the Registrants cannot predict when the regulatory agency will act or what action the regulatory agency will take. The Registrants' financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates.

FERC Proceedings

Order for Sponsored Transmission Upgrades within SPP

Under the SPP Open Access Transmission Tariff, costs of participant-funded, or "sponsored," transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP Open Access Transmission Tariff required the SPP to charge for these upgrades beginning in 2008, but the SPP had not been charging its customers for these upgrades due to information system limitations. However, the SPP had informed participants in the market that these charges would be forthcoming. In July 2016, the FERC granted the SPP's request to recover the charges not billed since 2008. The SPP subsequently billed OG&E for these charges and credited OG&E related to transmission upgrades that OG&E had sponsored, which resulted in OG&E being a net receiver of sponsored upgrade credits. The majority of these net credits were refunded to customers through OG&E's various rate riders that include SPP activity with the remaining amounts retained by OG&E.

Several companies that were net payers of Z2 charges sought rehearing of the FERC's July 2016 order; however, in November 2017, the FERC denied the rehearing requests. In January 2018, one of the impacted companies appealed the FERC's decision to the U.S. Court of Appeals for the District of Columbia Circuit. In July 2018, that court granted a motion requested by the FERC that the case be remanded back to the FERC for further examination and proceedings. In February 2019, the FERC reversed its July 2016 order and November 2017 rehearing denial, ruled that the SPP violated its tariff to charge for the 2008 - 2015 period in 2016, held that the SPP tariff provision that prohibited those charges could not be waived and ordered the SPP to develop a plan to refund the payments but not to implement the refunds until further ordered to do so. In response, in April 2019, OG&E filed a request for rehearing with the FERC, and in May 2019, OG&E filed a FERC 206 complaint against the SPP, alleging that the SPP's forced unwinding of the revenue credit payments to OG&E would violate the provisions of the Sponsored Upgrade Agreement and of the applicable tariff. OG&E's filing requested that the FERC rule that the SPP is not entitled to seek refunds or in any other way seek to unwind the revenue credit payments it had paid to OG&E pursuant to the Sponsored Upgrade Agreement. The SPP's response to OG&E's filing agreed that OG&E should be entitled to keep its Z2 payments and argued that the SPP should not be held responsible for those payments if refunds are ordered. Further, the SPP has requested the FERC to negotiate a global settlement with all impacted parties, including other project sponsors who, like OG&E, have also filed complaints at FERC contending that the payments they have received cannot properly be unwound.
On February 20, 2020, the FERC denied OG&E's request for rehearing of its February 2019 order, denying the waiver and ruling that the SPP must seek refunds from project sponsors for Z2 payments for the 2008 through 2015 period and pay them back to transmission owners. The FERC also denied the SPP's request for a stay and for institution of settlement procedures. The FERC stated it would not institute settlement procedures unless parties on both sides of the matter requested them. The FERC did not rule on OG&E's complaint or the complaints of other project sponsors, or consider the SPP's refund plan. The FERC thus has not set any date for payment of refunds. On March 2, 2020, OG&E petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the FERC's order denying the waiver and requiring refunds. The appeal will likely be decided by the second quarter of 2021.
The Registrants cannot predict the outcome of this proceeding based on currently available information, and as of December 31, 2020 and at present time, the Registrants have not reserved an amount for a potential refund. If the reversal of the July 2016 FERC order remains intact, OG&E estimates it would be required to refund $13.0 million, which is net of amounts paid to other utilities for upgrades and would be subject to interest at the FERC-approved rate. If refunds were required, recovery of these upgrade credits would shift to future periods. Of the $13.0 million, the Registrants would be impacted by $5.0 million in expense that initially benefited the Registrants in 2016, and OG&E customers would incur a net impact of $8.0 million in expense through rider mechanisms or the FERC formula rate.

On January 31, 2020, the FERC acted on an SPP proposal to eliminate Attachment Z2 revenue crediting and replace it with a different rate mechanism that would provide project sponsors, such as OG&E, the same level of recovery, and rejected the proposal to the extent it would limit recovery to the amount of the upgrade sponsor's directly assigned upgrade costs with interest. The SPP resubmitted a proposal on April 29, 2020 without this limited recovery, and with the alternative rate mechanism, and the FERC approved it on June 30, 2020, effective July 1, 2020. No party sought rehearing of the order, and it is


134

now final. This order would only prospectively impact OG&E and its recovery of any future upgrade costs that it may incur as a project sponsor. All of the existing projects that are eligible to receive revenue credits under Attachment Z2, which includes the $13.0 million at issue in OG&E's appeal as discussed above, will continue to do so.

APSC Proceedings

Arkansas 2020 Formula Rate Plan Filing

On October 1, 2020, OG&E filed its third evaluation report under its Formula Rate Plan, and on January 28, 2021, OG&E entered into a non-unanimous settlement agreement with the APSC General Staff and the Office of the Arkansas Attorney General. The only non-signatory to the settlement agreement has agreed not to oppose the settlement. The settlement agreement includes a revenue increase of $6.7 million, which is the maximum amount statutorily allowed in this filing. Additionally, the settling parties will not object to OG&E's request for a finding that the Arkansas Series II grid modernization projects included in this filing are prudent in cost. A final order is requested from the APSC in March 2021, and new rates will become effective April 1, 2021.

Disconnection Procedures Related to COVID-19

On September 17, 2020, the APSC issued Order No. 9 inviting comments from all jurisdictional utilities and any other interested stakeholders on specific questions related to whether a moratorium on service terminations should be lifted and if so, how the resumption of disconnections should occur. The APSC also ordered utilities to submit a detailed "Transitional Plan" outlining how utilities propose to reinstate routine service disconnection activities and collection of past due amounts once the moratorium is lifted. OG&E submitted its proposed Transitional Plan on October 14, 2020. The APSC General Staff thereafter filed reports for utilities that set forth recommendations as to the form of notice that should occur prior to lifting the moratorium and resuming disconnections, as well as payment arrangements that should be made available to customers.

On February 8, 2021, the APSC issued Order No. 15 announcing a target date of May 3, 2021 to lift the moratorium on disconnections and requiring certain conditions and requirements that utilities must meet before disconnections may resume. Such requirements include, among other things, immediate communication to customers, notice periods for disconnections and deferred payment arrangements. In the interim, the APSC is expected to continue to review all information relevant to a discontinuation of the moratorium and is expected to issue an order on March 26, 2021, either confirming the lifting of the moratorium on disconnections, or extending the moratorium.

OCC Proceedings

Oklahoma Retail Electric Supplier Certified Territory Act Causes

Several rural electric cooperative electricity suppliers have filed complaints with the OCC alleging that OG&E has violated the Oklahoma Retail Electric Supplier Certified Territory Act. OG&E believes it is lawfully serving customers specifically exempted from this act and has presented evidence and testimony to the OCC supporting its position. There have been five complaint cases initiated at the OCC, and the OCC has issued decisions on each of them. The OCC ruled in favor of the electric cooperatives in three of those cases and ruled in favor of OG&E in two of those cases. All five of those cases have been appealed to the Oklahoma Supreme Court, where they have been made companion cases but will be individually briefed and have individual final decisions.

If the Oklahoma Supreme Court ultimately were to find that some or all of the customers being served are not exempted from the Oklahoma Retail Electric Supplier Certified Territory Act, OG&E would have to evaluate the recoverability of some plant investments made to serve these customers. The total amount of OG&E's plant investments made to serve the customers in all five cases is approximately $28.0 million, of which $11.7 million applies to the three cases where the OCC ruled in favor of the electric cooperatives. In addition to the evaluation of the recoverability of the investments, OG&E may also be required to reimburse certified territory suppliers for an amount of lost revenue. The amount of such lost revenue would depend on how the OCC calculates the revenue requirement but could range from approximately $14.5 million to $21.7 million for all five cases, of which $1.4 million to $2.3 million would apply to the three cases where the OCC ruled in favor of the electric cooperatives.



135

October 2020 Storm Examination

In October 2020, a major ice storm moved through OG&E's service territory which caused significant damage to the system. On November 17, 2020, the Public Utility Division of the OCC initiated an examination and review of all distribution utilities and cooperatives affected by the storm into the mitigation efforts, restoration processes and proposed improvements for future related or similar events. Respondents are required to provide certain information related to the examination, and the OCC may request additional relief as the examination proceeds. No procedural schedule has been proposed currently; however, OG&E is responding to discovery requests.

February 2021 Extreme Cold Weather Event

In February 2021, OG&E's service territory experienced an unprecedented, prolonged, cold spell that resulted in record winter peak demand for electricity and extreme natural gas and purchased power prices. OG&E's natural gas costs for the month of February 2021 exceeded the total cost for all of 2020. Fuel and purchased power costs are recovered through OG&E's Oklahoma and Arkansas fuel adjustment clauses. Estimates of the total regulatory asset for fuel and purchased power costs that will be recorded are still under development but are expected to be in the range of $800.0 million to $1.0 billion. For approximately 58,000 guaranteed flat bill customers, representing approximately three percent of load, OG&E may be unable to seek recovery for the incremental fuel and purchased power costs that are included in customers' guaranteed flat bill agreements which would result in a loss to OG&E. Full impacts cannot be determined until all settlements and invoices are received for this period. While borrowing availability still exists within the Registrants' credit facilities, OGE Energy has secured a commitment for $1.0 billion in additional short-term financing to provide additional liquidity to help cover these increased fuel and purchased power costs. On February 24, 2021, OG&E submitted an application to the OCC outlining a two-step approach for regulatory treatment for the fuel and purchased power costs associated with the unprecedented weather event. The steps include: (i) an intra-year fuel clause increase to be effective April 1, 2021; and (ii) a request for regulatory asset treatment at OG&E's weighted average cost of capital for the remaining fuel and purchased power costs. OG&E anticipates making a similar filing with the APSC.


136

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Stockholders and the Board of Directors of OGE Energy Corp.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of OGE Energy Corp. (the Company) as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the "consolidated financial statements"). In our opinion, based on our audits and the report of other auditors, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

We did not audit the consolidated financial statements of Enable Midstream Partners, LP (Enable), a partnership in which the Company has a 25.5% interest. In the consolidated financial statements, the Company's investment in Enable is stated at $374.3 million and $1,132.9 million as of December 31, 2020 and 2019, respectively, and the Company's equity in the net income of Enable is stated at $13.2 million in 2020, $91.8 million in 2019 and $124.4 million in 2018. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Enable, is based solely on the report of the other auditors.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 24, 2021, expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.










137

Regulatory Assets and Liabilities

Description of the Matter
As discussed in Note 1 to the consolidated financial statements, the Company conducts its electric utility operations through Oklahoma Gas & Electric Company (OG&E). OG&E is a regulated utility subject to accounting principles for rate-regulated activities. As such, certain incurred costs that would otherwise be charged to expense are deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense are deferred as regulatory liabilities, based on the expected refund to customers in future rates. OG&E records items as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates.
Auditing regulatory assets and liabilities is complex as it requires specialized knowledge of rate-regulated activities and judgments as to matters that could affect the recording or updating of regulatory assets and liabilities.
How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design, and tested the operating effectiveness of internal controls over the Company’s accounting for regulatory assets and liabilities, including, among others, controls over management’s assessment of the likelihood of approval by regulators for new matters and controls over the evaluation of filings with regulatory bodies on existing regulatory assets and liabilities, including factors that may affect the timing or nature of recoverability.
We performed audit procedures that included, among others, reviewing evidence of correspondence with regulatory bodies to test that the Company appropriately evaluated new information obtained from regulatory rulings. For example, we assessed the recoverability, considering information obtained from regulatory rulings, of various regulatory assets. In addition, we tested that amortization of regulatory assets and liabilities corresponded to relevant regulatory rulings. For example, we tested whether the regulatory assets and liabilities were appropriately amortized through the Company’s rates charged to customers based on rulings from regulatory bodies.


/s/  Ernst & Young LLP
We have served as the Company's auditor since 2002.

Oklahoma City, Oklahoma

February 24, 2021




138

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Stockholder and Board of Directors of Oklahoma Gas and Electric Company

Opinion on the Financial Statements

We have audited the accompanying balance sheets and statements of capitalization of Oklahoma Gas & Electric Company (the Company) as of December 31, 2020 and 2019, the related statements of income, changes in stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 24, 2021, expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.


















139

Regulatory Assets and Liabilities

Description of the Matter As discussed in Note 1 to the financial statements, the Company is a regulated utility subject to accounting principles for rate-regulated activities. As such, certain incurred costs that would otherwise be charged to expense are deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense are deferred as regulatory liabilities, based on the expected refund to customers in future rates. The Company records items as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates.
Auditing regulatory assets and liabilities is complex as it requires specialized knowledge of rate-regulated activities and judgments as to matters that could affect the recording or updating of regulatory assets and liabilities.
How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design, and tested the operating effectiveness of internal controls over the Company’s accounting for regulatory assets and liabilities, including, among others, controls over management’s assessment of the likelihood of approval by regulators for new matters and controls over the evaluation of filings with regulatory bodies on existing regulatory assets and liabilities, including factors that may affect the timing or nature of recoverability.
We performed audit procedures that included, among others, reviewing evidence of correspondence with regulatory bodies to test that the Company appropriately evaluated new information obtained from regulatory rulings. For example, we assessed the recoverability, considering information obtained from regulatory rulings, of various regulatory assets. In addition, we tested that amortization of regulatory assets and liabilities corresponded to relevant regulatory rulings. For example, we tested whether the regulatory assets and liabilities were appropriately amortized through the Company’s rates charged to customers based on rulings from regulatory bodies.


/s/ Ernst & Young LLP
We have served as the Company's auditor since 2002.    

Oklahoma City, Oklahoma

February 24, 2021


140

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
 
None.

Item 9A. Controls and Procedures.
 
The Registrants maintain a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Registrants in reports that they file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer and chief financial officer, allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the Registrants' management, including the chief executive officer and chief financial officer, of the effectiveness of the Registrants' disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934), the chief executive officer and chief financial officer have concluded that the Registrants' disclosure controls and procedures are effective.
 
No change in the Registrants' internal control over financial reporting has occurred during the most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrants' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934).

While remote work arrangements were temporarily implemented in response to the COVID-19 pandemic, the Registrants believe there have been no material changes to the processes and procedures that impact financial reporting. The Registrants continue to monitor potential internal control impacts of COVID-19 and plan accordingly to ensure the effectiveness of the Registrants' internal controls over financial reporting and disclosures.



141

Management's Report on Internal Control Over Financial Reporting
The management of the Registrants is responsible for establishing and maintaining adequate internal control over financial reporting. The Registrants' internal control systems were designed to provide reasonable assurance to management and OGE Energy's Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
The Registrants' management assessed the effectiveness of their internal control over financial reporting as of December 31, 2020. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on our assessment, we believe that, as of December 31, 2020, the Registrants' internal control over financial reporting is effective based on those criteria.
The Registrants' independent auditors have issued an attestation report on the Registrants' internal control over financial reporting. This report appears on the following page.
/s/ Sean Trauschke /s/ Sarah R. Stafford
Sean Trauschke, Chairman of the Board, President Sarah R. Stafford, Controller
  and Chief Executive Officer   and Chief Accounting Officer
/s/ W. Bryan Buckler
W. Bryan Buckler
Chief Financial Officer



142

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of OGE Energy Corp.

Opinion on Internal Control over Financial Reporting

We have audited OGE Energy Corp.'s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, OGE Energy Corp. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets and consolidated statements of capitalization of OGE Energy Corp. as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and financial statement schedule listed in the Index at Item 15(a) and our report dated February 24, 2021 expressed an unqualified opinion thereon.

Basis for Opinion

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP
Oklahoma City, Oklahoma

February 24, 2021


143

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholder and the Board of Directors of Oklahoma Gas and Electric Company

Opinion on Internal Control over Financial Reporting

We have audited Oklahoma Gas and Electric Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Oklahoma Gas and Electric Company (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the balance sheets and statements of capitalization of Oklahoma Gas & Electric Company as of December 31, 2020 and 2019, the related statements of income, changes in stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and financial statement schedule listed in the Index at Item 15(a) and our report dated February 24, 2021 expressed an unqualified opinion thereon.

Basis for Opinion

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP
Oklahoma City, Oklahoma

February 24, 2021


144

Item 9B. Other Information.
On February 24, 2021, OGE Energy entered into a commitment letter with Wells Fargo and certain of its affiliates whereby Wells Fargo committed to provide an unsecured term loan facility in the aggregate principal amount of $1.0 billion. The commitment letter provides that the term loan facility will mature four months from closing, unless Wells Fargo is able to obtain commitments from other lenders in an amount of $650.0 million or more, in which event the facility will mature on the date that is 364 days from closing. The commitment letter provides that the term loan facility will includes events of default, covenants, representations and warranties and other terms and conditions substantially similar to OGE Energy's existing revolving credit facility.

Wells Fargo's commitment is subject to customary conditions, including negotiation of satisfactory definitive documentation. The term loan facility is anticipated to close on or about March 5, 2021.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.
 
Code of Ethics Policy
 
OGE Energy maintains a code of ethics for our chief executive officer and senior financial officers, including the chief financial officer and chief accounting officer, which is available for public viewing on OGE Energy's website address www.ogeenergy.com under the heading "Investors," "Governance." The code of ethics will be provided, free of charge, upon request. OGE Energy intends to satisfy the disclosure requirements under Section 5, Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the code of ethics by posting such information on its website at the location specified above. OGE Energy will also include in its proxy statement information regarding the Audit Committee financial experts.

OGE Energy. Item 10 information, other than information regarding the Code of Ethics, is omitted for OGE Energy pursuant to General Instruction G of Form 10-K, because OGE Energy will file copies of a definitive proxy statement with the Securities and Exchange Commission on or about April 5, 2021. Such proxy statement is incorporated herein by reference.

OG&E. Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 10 for OG&E has been omitted.

Item 11. Executive Compensation.

OGE Energy. Item 11 is omitted for OGE Energy pursuant to General Instruction G of Form 10-K, because OGE Energy will file copies of a definitive proxy statement with the Securities and Exchange Commission on or about April 5, 2021. Such proxy statement is incorporated herein by reference.

OG&E. Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 11 for OG&E has been omitted.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

OGE Energy. Item 12 is omitted for OGE Energy pursuant to General Instruction G of Form 10-K, because OGE Energy will file copies of a definitive proxy statement with the Securities and Exchange Commission on or about April 5, 2021. Such proxy statement is incorporated herein by reference.

OG&E. Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 12 for OG&E has been omitted.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

OGE Energy. Item 13 is omitted for OGE Energy pursuant to General Instruction G of Form 10-K, because OGE Energy will file copies of a definitive proxy statement with the Securities and Exchange Commission on or about April 5, 2021. Such proxy statement is incorporated herein by reference.



145

OG&E. Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 13 for OG&E has been omitted.

Item 14. Principal Accountant Fees and Services.
 
OGE Energy. Item 14 is omitted pursuant to General Instruction G of Form 10-K, because OGE Energy will file copies of a definitive proxy statement with the Securities and Exchange Commission on or about April 5, 2021. Such proxy statement is incorporated herein by reference.

OG&E. The following discussion relates to the audit fees paid by OGE Energy to its principal independent accountants for the services provided to OGE Energy and its subsidiaries, including OG&E.

Fees for Principal Independent Accountants
Year Ended December 31 2020 2019
Integrated audit of OGE Energy and its subsidiaries financial statements and internal control over financial reporting $ 1,136,800  $ 1,171,100 
Services in support of debt and stock offerings 65,000  45,000 
Other (A) 325,000  319,500 
Total audit fees (B) 1,526,800  1,535,600 
Employee benefit plan audits 128,000  149,000 
Total audit-related fees 128,000  149,000 
Assistance with examinations and other return issues 65,948  79,200 
Review of federal and state tax returns 32,000  34,000 
Total tax preparation and compliance fees 97,948  113,200 
Total tax fees 97,948  113,200 
Total fees $ 1,752,748  $ 1,797,800 
(A)Includes reviews of the financial statements included in the Registrants' Quarterly Reports on Form 10-Q, audits of OGE Energy's subsidiaries, preparation for Audit Committee meetings and fees for consulting with the Registrants' executives regarding accounting issues.
(B)The aggregate audit fees include fees billed for the audit of the Registrants' annual financial statements and for the reviews of the financial statements included in the Registrants' Quarterly Reports on Form 10-Q. For 2020, this amount includes estimated billings for the completion of the 2020 audit, which services were rendered after year-end.

All Other Fees

There were no other fees billed by the principal independent accountants to OGE Energy in 2020 and 2019 for other services.

Audit Committee Pre-Approval Procedures

Rules adopted by the Securities and Exchange Commission in order to implement requirements of the Sarbanes-Oxley Act of 2002 require public company audit committees to pre-approve audit and non-audit services. OGE Energy's Audit Committee follows procedures pursuant to which audit, audit-related and tax services, and all permissible non-audit services are pre-approved by category of service. The fees are budgeted, and actual fees versus the budget are monitored throughout the year. During the year, circumstances may arise when it may become necessary to engage the principal independent accountants for additional services not contemplated in the original pre-approval. In those instances, OGE Energy will obtain the specific pre-approval of the Audit Committee before engaging the principal independent accountants. The procedures require the Audit Committee to be informed of each service, and the procedures do not include any delegation of the Audit Committee's responsibilities to management. The Audit Committee may delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated will report any pre-approval decisions to the Audit Committee at its next scheduled meeting.
 
For 2020, 100 percent of the audit fees, audit-related fees and tax fees were pre-approved by the Audit Committee or the Chairman of the Audit Committee pursuant to delegated authority. 




146

PART IV

Item 15. Exhibit and Financial Statement Schedules.

(a) 1. Financial Statements
 
(i)The following financial statements are included in Part II, Item 8 of this Annual Report:

OGE Energy

•Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018
•Consolidated Statements of Comprehensive Income for the years ended December 31, 2020, 2019 and 2018
•Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018
•Consolidated Balance Sheets at December 31, 2020 and 2019
•Consolidated Statements of Capitalization at December 31, 2020 and 2019
•Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2020, 2019 and 2018
•Notes to Consolidated Financial Statements
•Report of Independent Registered Public Accounting Firm (Audit of Financial Statements)
•Management's Report on Internal Control Over Financial Reporting
•Report of Independent Registered Public Accounting Firm (Audit of Internal Control over Financial Reporting)

OG&E

•Statements of Income for the years ended December 31, 2020, 2019 and 2018
•Statements of Comprehensive Income for the years ended December 31, 2020, 2019 and 2018
•Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018
•Balance Sheets at December 31, 2020 and 2019
•Statements of Capitalization at December 31, 2020 and 2019
•Statements of Changes in Stockholder's Equity for the years ended December 31, 2020, 2019 and 2018
•Notes to Financial Statements
•Report of Independent Registered Public Accounting Firm (Audit of Financial Statements)
•Management's Report on Internal Control Over Financial Reporting
•Report of Independent Registered Public Accounting Firm (Audit of Internal Control over Financial Reporting)

(i)The financial statements and Notes to Consolidated Financial Statements of Enable Midstream Partners, LP, required pursuant to Rule 3-09 of Regulation S-X are filed as Exhibit 99.01.

2. Financial Statement Schedule (included in Part IV)                            

•Schedule II - Valuation and Qualifying Accounts    

All other schedules have been omitted since the required information is not applicable or is not material, or because the information required is included in the respective financial statements or notes thereto.



147

3. Exhibits
Exhibit No.  Description OGE Energy OG&E
2.01 X
3.01 X
3.02 X
3.03 X
3.04 X
4.01 X X
4.02 X X
4.03 X X
4.04 X X
4.05 X X
4.06 X X
4.07 X X
4.08 X X
4.09 X X
4.10 X X
4.11 X X
4.12 X X
4.13 X X


148

4.14 X X
4.15 X X
4.16 X X
4.17 X X
4.18 X X
4.19 X X
4.20 X X
4.21 X
4.22 X
4.23 X
4.24+
X
10.01 X X
10.02 X X
10.03 X X
10.04* X X
10.05 X
10.06 X X


149

10.07* X X
10.08* X X
10.09* X X
10.10 X X
10.11* X X
10.12*+ X X
10.13*+ X X
10.14 X
10.15 X
10.16 X
10.17 X
10.18* X X
10.19* X X
10.20* X
10.21* X
10.22* X X
10.23* X X
10.24* X X
10.25 X X


150

10.26 X X
10.27*+ X X
10.28 X X
10.29 X
10.30 X
10.31 X
10.32+ X
21.01+ X
23.01+ X
23.02+ X
23.03+ X
24.01+ X
24.02+ X
31.01+ X
31.02+ X
32.01+ X
32.02+ X
99.01+ X
99.02 X X
99.03 X X


151

101.INS Inline XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document. X X
101.SCH Inline XBRL Taxonomy Schema Document. X X
101.PRE Inline XBRL Taxonomy Presentation Linkbase Document. X X
101.LAB Inline XBRL Taxonomy Label Linkbase Document. X X
101.CAL Inline XBRL Taxonomy Calculation Linkbase Document. X X
101.DEF Inline XBRL Definition Linkbase Document. X X
104 Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (included in Exhibit 101). X X
 * Represents executive compensation plans and arrangements.
 + Represents exhibits filed herewith. All exhibits not so designated are incorporated by reference to a
prior filing, as indicated.



152

OGE ENERGY CORP.
OKLAHOMA GAS AND ELECTRIC COMPANY

SCHEDULE II - Valuation and Qualifying Accounts

Additions
Description Balance at Beginning of Period Charged to Costs and Expenses Deductions (A) Balance at End of Period
(In millions)
Balance at December 31, 2018
Reserve for Uncollectible Accounts $ 1.5  $ 3.4  $ 3.2  $ 1.7 
Balance at December 31, 2019
Reserve for Uncollectible Accounts $ 1.7  $ 2.2  $ 2.4  $ 1.5 
Balance at December 31, 2020
Reserve for Uncollectible Accounts $ 1.5  $ 3.0  $ 1.9  $ 2.6 
(A)Uncollectible accounts receivable written off, net of recoveries.

Item 16. Form 10-K Summary.

None.


153


SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on February 24th, 2021.

  OGE ENERGY CORP.  
  (Registrant)  
     
  By /s/ Sean Trauschke  
  Sean Trauschke  
  Chairman of the Board, President  
  and Chief Executive Officer  

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
Signature Title Date
/s/ Sean Trauschke    
Sean Trauschke Principal Executive  
Officer and Director; February 24, 2021
/s/ W. Bryan Buckler
W. Bryan Buckler Principal Financial Officer; February 24, 2021
/s/ Sarah R. Stafford
Sarah R. Stafford Principal Accounting Officer. February 24, 2021
Frank A. Bozich Director;  
James H. Brandi Director;  
Peter D. Clarke Director;
Luke R. Corbett Director;  
David L. Hauser Director;  
Luther C. Kissam, IV Director;  
Judy R. McReynolds Director;
David E. Rainbolt Director;
J. Michael Sanner Director;
Sheila G. Talton Director;

/s/ Sean Trauschke    
By Sean Trauschke (attorney-in-fact) February 24, 2021



154

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on February 24th, 2021.


OKLAHOMA GAS AND ELECTRIC COMPANY
  (Registrant)  
     
  By /s/ Sean Trauschke  
  Sean Trauschke  
  Chairman of the Board, President  
  and Chief Executive Officer  

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.

Signature Title Date
/s/ Sean Trauschke
Sean Trauschke Principal Executive
Officer and Director; February 24, 2021
/s/ W. Bryan Buckler
W. Bryan Buckler Principal Financial Officer; February 24, 2021
/s/ Sarah R. Stafford
Sarah R. Stafford Principal Accounting Officer. February 24, 2021
Frank A. Bozich Director;
James H. Brandi Director;
Peter D. Clarke Director;
Luke R. Corbett Director;
David L. Hauser Director;
Luther C. Kissam, IV Director;
Judy R. McReynolds Director;
David E. Rainbolt Director;
J. Michael Sanner Director;
Sheila G. Talton Director;

/s/ Sean Trauschke
By Sean Trauschke (attorney-in-fact) February 24, 2021



155
Exhibit 4.24
DESCRIPTION OF SECURITIES

The following description of the common stock of OGE Energy Corp., an Oklahoma corporation, is a summary of the general terms thereof and is qualified in its entirety by the provisions of our certificate of incorporation, as amended and restated (the "Restated Certificate of Incorporation"), and bylaws, as amended and restated (the "Bylaws"), copies of both of which have been filed as exhibits to our most recent Annual Report on Form 10-K filed with the Securities and Exchange Commission, and the laws of the state of Oklahoma.

Authorized Shares

Under our Restated Certificate of Incorporation, we are authorized to issue 450,000,000 shares of common stock, par value $0.01 per share, of which 200,021,161 shares were outstanding on January 29, 2021. We are also authorized to issue 5,000,000 shares of preferred stock, par value $0.01 per share. No shares of preferred stock are currently outstanding. Our common stock is our only security registered under Section 12 of the Securities Exchange Act of 1934.

Without shareholder approval, we may issue preferred stock in the future in such series as may be designated by our board of directors. In creating any such series, our board of directors has the authority to fix the rights and preferences of each series with respect to, among other things, the dividend rate, redemption provisions, liquidation preferences, sinking fund provisions, conversion rights and voting rights. The terms of any series of preferred stock that we may issue in the future may provide the holders of such preferred stock with rights that are senior to the rights of the holders of our common stock.

Dividend Rights

Before we can pay any dividends on our common stock, the holders of our preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. Currently, there are no shares of our preferred stock outstanding. Because we are a holding company and conduct all of our operations through our subsidiary and our equity investments, our cash flow and ability to pay dividends will be dependent on the earnings and cash flows of our subsidiary and our unconsolidated affiliate and the distribution or other payment of those earnings to us in the form of dividends or distributions, or in the form of repayments of loans or advances to us. We expect to derive principally all of the funds required by us to enable us to pay dividends on our common stock from dividends paid by Oklahoma Gas and Electric Company ("OG&E"), on OG&E's common stock, and from distributions paid by OGE Holdings on its interest in Enable Midstream Partners, LP ("Enable"). Our ability to receive dividends on OG&E's common stock is subject to the prior rights of the holders of any OG&E preferred stock that may be outstanding, any covenants of OG&E's certificate of incorporation and OG&E's debt instruments limiting the ability of OG&E to pay dividends and the ability of public utility commissions that regulate OG&E to effectively restrict the payment of dividends by OG&E. Our ability to receive distributions from Enable through our interest in OGE Holdings is dependent upon the cash flow of Enable and is subject to the prior rights of the holders of any Enable preferred units and any covenants of Enable’s debt instruments limiting the ability of Enable to pay distributions.

Voting Rights

Each holder of common stock is entitled to one vote per share upon all matters upon which shareowners have the right to vote and generally will vote together as one class. Our board of directors has the authority to fix conversion and voting rights for any new series of preferred stock (including the right to elect directors upon a failure to pay dividends), provided that no share of preferred stock can have more than one vote per share.

Our Restated Certificate of Incorporation also contains "fair price" provisions, which require the approval by the holders of at least 80 percent of the voting power of our outstanding voting stock as a condition for mergers, consolidations, sales of substantial assets, issuances of capital stock and certain other business combinations and transactions involving us and any substantial (10 percent or more) holder of our voting stock unless the transaction is either approved by a majority of the members of our board of directors who are unaffiliated with the substantial

Exhibit 4.24
holder or specified minimum price and procedural requirements are met. The provisions summarized in the foregoing sentence may be amended only by the approval of the holders of at least 80 percent of the voting power of our outstanding voting stock. Our voting stock consists of all outstanding shares entitled to vote generally in the election of directors and currently consists of our common stock.

Our voting stock does not have cumulative voting rights for the election of directors. Our Restated Certificate of Incorporation and By- Laws currently contain provisions stating that: (1) directors may be removed only with the approval of the holders of at least a majority of the voting power of our shares generally entitled to vote; (2) any vacancy on the board of directors will be filled only by the remaining directors then in office, though less than a quorum; (3) advance notice of introduction by shareowners of business at annual shareowner meetings and of shareowner nominations for the election of directors must be given and that certain information must be provided with respect to such matters; (4) shareowner action may be taken only at an annual meeting of shareowners or a special meeting of shareowners called by the President or the board of directors; and (5) the foregoing provisions may be amended only by the approval of the holders of at least 80 percent of the voting power of the shares generally entitled to vote. These provisions, along with the "fair price" provisions discussed above, the business combination and control share acquisition provision discussed below, may deter attempts to cause a change in control of our company (by proxy contest, tender offer or otherwise) and will make more difficult a change in control that is opposed by our board of directors.

Liquidation Rights

Subject to possible prior rights of holders of preferred stock that may be issued in the future, in the event of our liquidation, dissolution or winding up, whether voluntary or involuntary, the holders of our common stock are entitled to receive the remaining assets and funds pro rata, according to the number of shares of common stock held.

Other Provisions

Oklahoma has enacted legislation aimed at regulating takeovers of corporations and restricting specified business combinations with interested shareholders. Under the Oklahoma General Corporation Act, a shareowner who acquires more than 15 percent of the outstanding voting shares of a corporation subject to the statute, but less than 85 percent of such shares, is prohibited from engaging in specified "business combinations" with the corporation for three years after the date that the shareowner became an interested stockholder. This provision does not apply if (1) before the acquisition date the corporation's board of directors has approved either the business combination or the transaction in which the shareowner became an interested shareowner or (2) the corporation's board of directors approves the business combination and at least two- thirds of the outstanding voting stock of the corporation not owned by the interested shareowner vote to authorize the business combination. The term "business combination" encompasses a wide variety of transactions with or caused by an interested shareowner in which the interested shareowner receives or could receive a benefit on other than a pro rata basis with other shareowners, including mergers, specified asset sales, specified issuances of additional shares to the interested shareowner, transactions with the corporation that increase the proportionate interest of the interested shareowner or transactions in which the interested shareowner receives certain other benefits.

Oklahoma law also contains control share acquisition provisions. These provisions generally require the approval of the holders of a majority of the corporation's voting shares held by disinterested shareowners before a person purchasing one-fifth or more of the corporation's voting shares can vote the shares in excess of the one-fifth interest. Similar shareholder approvals are required at one-third and majority thresholds.

The board of directors may allot and issue shares of common stock for such consideration, not less than the par value thereof, as it may from time to time determine. No holder of common stock has the preemptive right to subscribe for or purchase any part of any new or additional issue of stock or securities convertible into stock. Our common stock is not subject to further calls or to assessment by us.


Exhibit 4.24
Listing

Our common stock is listed on the New York Stock Exchange.

Transfer Agent and Registrar

Computershare is the Transfer Agent and Registrar for our common stock.


Exhibit 10.12

OGE Energy Corp.
Director Compensation
Compensation of non-management directors of OGE Energy Corp. ("OGE Energy") in 2020 included an annual retainer fee of $235,000, of which $105,000 was payable in cash in quarterly installments and $130,000 was deposited in the director's account under OGE Energy's Deferred Compensation Plan and converted to 3,995.0 common stock units based on the closing price of OGE Energy's Common Stock on December 8, 2020. In 2020, the independent directors did not receive additional compensation for attending Board or committee meetings but were instead paid a quarterly cash retainer. The lead director that served in 2020 received an additional $30,000 cash retainer in 2020. The chair of each of the Compensation, Nominating and Corporate Governance and Audit Committees that served in 2020 received an additional $15,000 annual cash retainer in 2020. Each member of the Audit Committee also received an additional annual retainer of $5,000. These amounts represent the total fees paid to directors in their capacities as directors of OGE Energy and Oklahoma Gas and Electric Company in 2020.

Under OGE Energy's Deferred Compensation Plan, non-management directors may defer payment of all or part of their quarterly and annual cash retainer fee, which deferred amounts in 2020 were credited to their account as of the scheduled payment date. Amounts credited to the accounts are assumed to be invested in one or more of the investment options permitted under OGE Energy's Deferred Compensation Plan. In 2020, those investment options included an OGE Energy Common Stock fund, whose value was determined based on the stock price of OGE Energy's Common Stock. When an individual ceases to be a director of OGE Energy, all amounts credited under OGE Energy's Deferred Compensation Plan are paid in cash in a lump sum or installments. In certain circumstances, participants may also be entitled to in-service withdrawals from OGE Energy's Deferred Compensation Plan.

On December 2, 2020, the Compensation Committee met to consider director compensation. At that meeting, the Compensation Committee decided to make no changes to the current director compensation package.


Exhibit 10.13

OGE Energy Corp.
Executive Officer Compensation
Executive Compensation
In December 2020, the Compensation Committee of the OGE Energy Corp. ("OGE Energy") board of directors took actions setting executives' salaries and target amount of annual incentive awards for 2021. In February 2021, the Compensation Committee took action setting executives' target amounts of long-term compensation awards for 2021. Executive compensation was set by the Compensation Committee after consideration of, among other things, individual performance and market-based data on compensation for executives with similar duties. Payouts of 2021 annual incentive award targets and performance-based long-term awards are dependent on achievement of specified corporate goals established by the Compensation Committee, and no officer is assured of any payout.
Salary
The Compensation Committee established the base salaries for its senior executive group. The salaries for 2021 for the current OGE Energy officers who are expected to be named in the Summary Compensation Table in OGE Energy's 2021 Proxy Statement are listed in the table below. The Summary Compensation Table in OGE Energy's 2021 Proxy Statement is expected to include three named executive officers for 2020 that will not receive compensation in 2021, due to their retirement from OGE Energy.
Executive Officer 2021 Base Salary
Sean Trauschke, Chairman, President and Chief Executive Officer $1,071,005
William H. Sultemeier, General Counsel $460,000
Donnie O. Jones, Vice President - Utility Operations of OG&E $323,000

Establishment of 2021 Annual Incentive Awards

As stated above, at its December 2020 meeting, the Compensation Committee approved the target amount of annual incentive awards, expressed as a percentage of salary, with the officer having the ability, depending upon achievement of the 2021 corporate goals to receive from 0 percent to 150 percent of such targeted amount. For 2021, the targeted amount ranged from 65 percent to 110 percent of the approved 2021 base salary for the executive officers in the above table.

Establishment of Long-Term Awards

At its February 2021 meeting, the Compensation Committee approved the level of target long-term incentive awards, expressed as a percentage of salary. For 2021, the targeted amount ranged from 110 percent to 320 percent of the approved 2021 base salary for the executive officers in the above table. The performance-based portion of the long-term incentive awards allow the officer to receive from 0 percent to 200 percent of such targeted amount at the end of a three-year performance period depending upon achievement of the corporate goals. The time-based portion of the long-term incentive awards allow the officers to receive the granted amount at the end of a three-year vesting period depending upon continued employment.

Other Benefits

Retirement Benefits. A significant amount of OGE Energy's employees hired before December 1, 2009, including executive officers, are eligible to participate in OGE Energy's Pension Plan and certain employees are eligible to participate in OGE Energy's Restoration of Retirement Income Plan that enables participants, including executive officers, to receive the same benefits that they would have received under OGE Energy's Pension Plan in the absence of limitations imposed by the federal tax laws. In addition, the supplemental executive retirement plan, which was adopted in 1993 and amended in subsequent years, provides a supplemental executive retirement plan in order to attract and retain executives designated by the Compensation Committee of OGE Energy's Board of Directors who may not otherwise qualify for a sufficient level of benefits under OGE Energy's Pension Plan and Restoration of Retirement Income Plan. Mr. Trauschke is the only employee who participates in the supplemental executive retirement plan.

Almost all employees of OGE Energy, including executive officers, also are eligible to participate in our 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have attained age 50 before the close of a year are allowed to


make additional contributions referred to as "Catch-Up Contributions," subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof; (ii) an after-tax Roth contribution; or (iii) a contribution made on a non-Roth after-tax basis. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have his or her future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election. For employees hired or rehired on or after December 1, 2009, OGE Energy contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation. OGE Energy contribution for employees hired or rehired before December 1, 2009 varies depending on the participant's hire date, election with respect to participation in the Pension Plan and, in some cases, years of service.

No OGE Energy contributions are made with respect to a participant's Catch-Up Contributions, rollover contributions, or with respect to a participant's contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Once made, OGE Energy's contribution may be directed to any available investment option in the 401(k) Plan. OGE Energy match contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their OGE Energy contribution account and become fully vested on completing three years of service. In addition, participants fully vest when they are eligible for normal or early retirement under the Pension Plan, in the event of their termination due to death or permanent disability or upon attainment of age 65 while employed by OGE Energy or its affiliates.

OGE Energy provides a nonqualified deferred compensation plan which is intended to be an unfunded plan. The plan's primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of OGE Energy and to supplement such employees' 401(k) Plan contributions as well as offering this plan to be competitive in the marketplace. Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of annual incentive awards or (ii) eligible employees may elect a deferral percentage of base salary and annual incentive awards based on the deferral percentage elected for a year under the 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) Plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors' meeting fees and annual retainers.

OGE Energy matches employee (but not non-employee director) deferrals to make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan, and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on prior participant elections, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after three years or, if earlier, on retirement, disability, death, a change in control of OGE Energy or termination of the plan.

Deferrals, plus any OGE Energy match, are credited to a recordkeeping account in the participant's name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. In 2020, those investment options included an OGE Energy Common Stock fund, whose value was determined based on the stock price of OGE Energy's Common Stock.

Normally, payments under the deferred compensation plan begin within one year after retirement. For these purposes, normal retirement age is 65 and the minimum age to qualify for early retirement is age 55 with at least five years of service. Benefits will be paid, at the election of the participant, either in a lump sum or a stream of annual payments for up to 15 years, or a combination thereof. Participants whose employment terminates before they qualify for retirement will receive their vested account balance in one lump sum following termination as provided in the plan. Participants also will be entitled to pre- and post-retirement survivor benefits. If the participant dies while in employment before retirement, his or her beneficiary will receive a payment of the account balance plus a supplemental survivor benefit equal to two times the total amount of base salary and annual incentive payments deferred under the plan. If the participant dies following retirement, his or her beneficiary will continue to receive the remaining vested account balance. Additionally, eligible surviving spouses will be entitled to a lifetime survivor annuity payable annually. The amount of the annuity is based on 50 percent of the participant's account balance at retirement, the spouse's age and actuarial assumptions established by OGE Energy's Plan Administration Committee.

At any time prior to retirement, a participant may withdraw all or part of amounts attributable to his or her vested account balance under the deferred compensation plan at December 31, 2004, subject to a penalty of 10 percent of the amount


withdrawn. In addition, at the time of the initial deferral election, a participant may elect to receive one or more in-service distributions on specified dates without penalty. Hardship withdrawals, without penalty, may also be permitted at the discretion of OGE Energy's Plan Administration Committee.

Perquisites. OGE Energy also offers executive officers a limited amount of perquisites. These include payment of social membership dues at dining and country clubs for certain executive officers, an annual physical exam for all executive officers, a relocation program and in some instances the use of a company car. In reviewing the perquisites and the benefits under the 401(k) Plan, Deferred Compensation Plan, Pension Plan, Restoration of Retirement Income Plan and supplemental executive retirement plan, the Compensation Committee seeks to provide participants with benefits at least commensurate with those offered by other utilities of comparable size.

Change-of-Control Provisions and Employment Agreements. None of OGE Energy's executive officers has an employment agreement with OGE Energy. Each of the executive officers has a change of control agreement that becomes effective upon a change of control. If an executive officer's employment is terminated by OGE Energy "without cause" following a change of control, the executive officer is entitled to the following payments: (i) all accrued and unpaid compensation and a prorated annual incentive payout and (ii) a severance payment equal to 2.99 times the sum of such officer's (a) annual base salary and (b) highest recent annual incentive payout. The change of control agreements are considered to be double trigger agreements because payment will only be made following a change of control and termination of employment. The 2.99 times multiple for change-of-control payments was selected because at the time it was considered standard. Although many companies also include provisions for tax gross-up payments to cover any excise taxes on excess parachute payments, OGE Energy's Board of Directors decided not to include this additional benefit in OGE Energy's agreements. Instead, under OGE Energy's agreements if the excise tax would be imposed, the change-of-control payments will be reduced to a point where no excise tax would be payable, if such reduction would result in a greater after-tax payment.

In addition, pursuant to the terms of OGE Energy's incentive compensation plans, upon a change of control, all performance units will vest and be paid out immediately in cash as if the applicable performance goals had been satisfied at target levels; all restricted stock units will vest and be paid out immediately in cash; and any annual incentive award outstanding for the year in which the participant's termination occurs for any reason, other than cause, within 24 months after the change of control will be paid in cash at target level on a prorated basis.

Appointment of W. Bryan Buckler as Chief Financial Officer

In December 2020, OGE Energy's Board of Directors named W. Bryan Buckler as Chief Financial Officer, effective January 1, 2021. In connection with his appointment, OGE Energy and Mr. Buckler entered into an employment arrangement, the terms of which are summarized below. Under his employment arrangement, Mr. Buckler's initial base salary will be at the annual rate of $400,000. Mr. Buckler will receive a cash signing and retention bonus of $175,000, payable in three installments, with $25,000 payable on the first pay period after his start date of January 1, 2021, $50,000 payable on the first pay period following December 31, 2021, and the remaining $100,000 payable on the first pay period following December 31, 2022 (provided, in each case, he is still employed). If Mr. Buckler voluntarily resigns or is terminated for cause within two years after his start date, he will forfeit the entire $175,000 signing bonus and must repay any such amounts previously paid, including amounts withheld for taxes. Mr. Buckler will also be eligible to participate in the OGE Energy Corp. Annual Incentive Compensation Plan for the 2021 plan year through a target individual award of 70 percent of his base salary. Mr. Buckler will also receive an award of three grants of long-term incentive awards under the OGE Energy Corp. 2013 Stock Incentive Plan. The first grant will be restricted stock units valued at $148,240 with a grant date of January 4, 2021 with a three-year vesting schedule with 57 percent of the units vesting on February 28, 2021, 34 percent of the units vesting on February 28, 2022, and 9 percent of the units vesting on February 28, 2023 and will include accrued dividends for the vesting period. The second grant will be performance units valued at $95,200 based on total shareholder return over a two-year period of January 1, 2021 to December 31, 2022, with earned payouts for the grant ranging from 0 percent to 200 percent and will include earned accrued dividends for the performance period. The third grant is expected to be made in February 2021 at the same time, and on the same terms, as the long-term awards made to the other executive officers. This grant will have a targeted payout equal to 150 percent of his base salary. This grant will include two components: (i) performance units, which will constitute 75 percent of the award and be payable based on achievement of specified total shareholder return over the three year period January 1, 2021 to December 31, 2023, with earned payouts for the grant ranging from 0 percent to 200 percent and (ii) restricted stock units, which will constitute 25 percent of the award, and will have a three-year cliff vesting period. In each case, these grants will be similar to the grants made to OGE Energy's other executive officers with accrued earned dividends for the performance and vesting period. If OGE Energy should terminate Mr. Buckler's employment within one year of his start date, other than for cause, OGE Energy shall pay Mr. Buckler an amount equal to the greater of his base salary at the time or $400,000. Mr. Buckler will also be provided relocation assistance, which includes, among other things, assistance up to a certain amount for house hunting trips, moving expenses, reimbursement of real estate commissions on the sale of his existing residence and


interim living expenses. If Mr. Buckler decides to terminate employment prior to his one-year anniversary date, he agrees to repay the full amount of certain moving expenses including applicable taxes. If Mr. Buckler decides to terminate employment prior to his two-year anniversary date, he agrees to repay a pro-rated amount of the relocation including applicable taxes.

Exhibit 10.27
October 22, 2020

Mr. Bryan Buckler
2238 Grimmersborough Lane
Charlotte, NC 28270

Dear Bryan,

We are pleased to offer you the position of Chief Financial Officer for OGE Energy Corp. (“OGE”) and Oklahoma Gas and Electric Company (“OG&E”) and look forward to your acceptance by October 26, 2020. The terms of this letter are subject to the approval of the Board of Directors of OGE and OG&E and to the approval of the Compensation Committee of the OGE Board of Directors, which we will promptly seek.

The fundamental elements of the offer include:

Position: Chief Financial Officer
Start Date: January 1, 2021 (with January 4 as the first workday)
Initial Base Salary: Your initial base salary will be at the annual rate of $400,000
Annual Short-Term Incentive Bonus
Plan:
You will be eligible to receive a Target Individual Award for 2021 paid in 2022 under the OGE Energy Corp. 2013 Annual Incentive Compensation Plan (the “Annual Bonus Plan”) of 70% of your base salary. The performance goals for your Target Individual Award and the portion of your award dependent on such performance goals will be approved by the Compensation Committee (the “Compensation Committee”) of the Board of Directors of OGE at its meeting in February 2021. The earned payout potential for this award will be between zero and 150% of the target, with the payout during the first quarter of 2022.
Long-Term Incentive Plan: You will be eligible to receive three Long-Term Incentive Awards under the OGE Corp. 2013 Stock Incentive Plan (the “Stock Plan”).
The first award consists of a grant tied to an annual target for the Chief Financial Officer position that is equal to 150% of your base salary. This grant consists of (a) 75% Performance Units (based on total shareholder return of OG&E stock over a three-year period of time) and (b) 25% Restricted Stock Units with a three-year cliff vesting period. The earned payout for the Performance Unit grant will be between zero and 200%. The precise terms of this award will be governed by an agreement, which will be provided to you, and by the Stock Plan. Your grant will include accrued dividends for the performance and vesting period. Your receipt of this grant is subject to approval of the Compensation Committee during its February 2021 meeting.
To account for the unvested restricted stock grants you are walking away from, the second award of Restricted Stock will be valued at $148,240 on the grant date of January 4, 2021. The grant will have a 3-year vesting schedule with 57% of the units vesting on February 28, 2021, 34% of the units vesting on February 28, 2022, and 9% of the units vesting on February 28, 2023. The precise terms of this award will be governed by an agreement, which will be provided to you, and by the Stock Plan. Your grant will include accrued dividends for the performance and vesting period. Your receipt of this grant is subject to approval of the Compensation Committee during its November 2020 meeting.


Exhibit 10.27

To account for the unvested performance-based stock grants you are walking away from, the third award of Performance Units will be valued at $95,200 on the grant date of January 4, 2021. These units will be based on total shareholder return of OG&E stock over a two-year period of time ending December 31, 2022. The precise terms of this award will be governed by an agreement, which will be provided to you, and by the Stock Plan. Your grants will include accrued dividends for the performance and vesting period. Your receipt of this grant is subject to approval of the Compensation Committee during its November 2020 meeting.
Subsequent awards of grants will be submitted through the annual Long-Term Incentive granting process during the first quarter of each year.
Retention Award: To account for the Retention Award you are walking away from, you will be eligible to receive a total cash payment of $175,000 over three installment payments as outlined in the attached Retention Agreement.
Relocation - Buyer Value Option:
You will receive the following assistance as coordinated by OGE Energy Corp and Weichert Workforce Mobility:

•Payment of home sale closing cost

•New home purchase closing cost up to $5,000

•Moving expenses, including packing and unpacking of household goods and personal effects and transportation to the new location for you and your family up to $25,000

•Lump sum miscellaneous allowance of $8,500 (includes commuting, temporary living, house finding, final move)

•Payment of storage fees for up to 90 days
If you decide to terminate employment prior to the one-year anniversary date of your hire, you agree to repay the full amount of the cost incurred for your relocation including applicable taxes. If you decide to terminate employment prior to the two-year anniversary date of your hire, you agree to repay a pro-rated amount of the relocation including applicable taxes. Additional relocation program details will be provided by Scharon Cantrell, Sr. Manager of Workforce Solutions.
Health and Other Benefits: You will be eligible to participate in the health and each remaining employee benefit and related plan made available by OGE to its employees and employees of its subsidiaries to the extent as other employees of comparable position with OGE and subsidiaries (including the Deferred Compensation Plan). You will be provided with information concerning the terms (including eligibility) of our various benefits. Please note that coverage for you under the terms of the medical and dental plans will commence on the first day of employment.
Severance: If your employment with the Company is terminated without cause on or prior to December 31, 2021, you shall receive a severance payment equal to the greater of your base salary at the time or $400,000, subject to receipt by the Company of a standard release from you. “Cause” shall mean gross negligence or willful neglect by you in performance of your duties or your conviction of a felony.




Exhibit 10.27
401(k) Matching: You will be eligible to participate in the OGE 401(k) Plan allowing you to contribute towards your retirement, with OGE matching your contributions at 200% of the first 5% of your contribution as defined in the OGE 401(k) Plan.
Vacation: Commencing January 2021, you will be entitled to 5 weeks (25 days) of paid vacation annually in addition to all holidays observed by OGE.
All job offers are contingent on the successful completion with satisfactory results (satisfactory results are the sole discretion of the Company) of a pre-employment drug screen, and background investigation, including a credit check. The foregoing terms of employment are subject to reconsideration and change by the Company beginning in 2022 in the same manner that they are for other officers at the Company. Also, your employment with the Company is at-will and accordingly may be terminated by either you or the Company at any time. Neither this letter or any other oral or written representations may be considered a contract for employment for any specific period of time.

Once we receive your signed acceptance of this offer, we will contact you to begin your pre-employment process. Should you have any questions, please feel free to contact Scharon Cantrell, Sr. Manager of Workforce Solutions, at 405-553-3104.

Bryan, we are excited at the prospect of you joining our organization and look forward to a positive response. Please sign and return one copy of this letter to me by October 26, 2020, acknowledging your acceptance.

Sincerely,
/s/ Sean Trauschke
Sean Trauschke
Chairman, President and CEO
Agreed and Accepted
Name /s/ W. Bryan Buckler
Date Oct. 26, 2020




Exhibit 10.32

CONFIDENTIAL
February 23, 2021

OGE Energy Corp.
P.O. Box 321
321 North Harvey
Oklahoma City, Oklahoma 73101

Attention: Charles B. Walworth, Treasurer

Re: OGE Energy Corp. Commitment Letter $1.0 Billion Delayed Draw Term Loan Facility (“Commitment Letter”)

Ladies and Gentlemen:

OGE Energy Corp. (the “Company” or “you”) has requested a delayed draw term loan facility (the “Facility”) in the aggregate principal amount of $1,000,000,000 (the “Commitment”). The proceeds of the Facility will be used for general corporate purposes.

Wells Fargo Bank, National Association (“Wells Fargo Bank”) is pleased to agree to act as administrative agent (the “Agent”) under the Facility and to commit to provide 100% of the Commitment on the terms and subject to the conditions set forth herein and in the summary of terms and conditions attached hereto as Exhibit A (the “Term Sheet”).

In addition, Wells Fargo Securities, LLC (“Wells Fargo Securities” and collectively with Wells Fargo Bank, the “Wells Fargo Parties”) is pleased to agree to act as sole lead arranger and sole book runner (in such capacities, the “Arranger”) for the Facility and to syndicate the Facility to one or more other financial institutions (collectively with Wells Fargo Bank, the “Lenders”). For purposes hereof and the Term Sheet, a “Successful Syndication” shall mean that Wells Fargo Bank holds commitments or loans of not more than $350,000,000 in respect of the Facility. For the avoidance of doubt, the obligations of the Wells Fargo Parties under this Commitment Letter are not contingent upon a Successful Syndication. Wells Fargo Securities will, in a manner reasonably acceptable to and in consultation with the Company, manage all aspects of the syndication including, without limitation, subject to the Company’s approval (not to be unreasonably withheld or delayed), (i) the selection and number of potential lenders to be approached, (ii) the timing of all offers to potential lenders, (iii) the acceptance of commitments and (iv) the amounts accepted. Wells Fargo Bank reserves the right to assign a portion of its commitment to any of its Affiliates (as such term is defined in the Credit Agreement dated as of March 8, 2017 among the Borrower, the lenders party thereto, Wells Fargo Bank, National Association, as administrative agent, and the other agents party thereto (as amended by the First Amendment to Credit Agreement, dated as of January 12, 2021, the “Existing Credit Agreement”)) without the consent of the Company. The Arranger shall have the right, in consultation with you and subject to your approval (not to be unreasonably withheld or delayed), to award titles to other co-agents or arrangers who are Lenders that provide (or whose affiliates provide) commitments in respect of the Facility; provided that no other agents, co-agents, arrangers or bookrunners will be appointed, no other titles will be awarded and no compensation (other than to the Wells Fargo Parties or as expressly contemplated in this Commitment Letter) will be paid in connection with the Facility without the prior written approval of the Arranger (which shall not be unreasonably withheld, conditioned or delayed). Wells Fargo Securities will have “left” placement in any marketing materials or other documentation used in connection with the Facility.



To assist the Arranger in its syndication efforts to achieve a Successful Syndication, the Company shall (a) use commercially reasonable efforts to provide and to cause its advisors to provide the Arranger upon request with all information reasonably deemed necessary by it to complete a Successful Syndication, it being agreed that the only financial statements that shall be required to be provided by the Company are those that are otherwise publicly available, and (b) cause the management of the Company, if requested by the Arranger, to actively participate in and use commercially reasonable efforts to cause its advisors to actively participate in, both the preparation of an information package regarding the operations, forecasts and prospects of the Company and the presentation of the information to prospective Lenders at a single bank/investor meeting (which may be telephonic) or, if agreed to by the Company at additional bank/investor meetings (which may be telephonic).

The Commitment of Wells Fargo Bank, the undertakings of the Arranger and effectiveness of the Facility are subject to the following: (i) the preparation, execution and delivery of a credit agreement (“Credit Agreement”), by and among the Company, the lenders party thereto and agented by the Agent, and other loan documents of a type substantially similar to the loan documents entered into in connection with the Existing Credit Agreement (collectively, together with the Credit Agreement, the “Loan Documents”), in each case, substantially reflecting and consistent with the terms and conditions set forth herein, in the Term Sheet, and the Fee Letter (as defined below) and/or as otherwise mutually agreed; (ii) except as set forth in writing to the Arranger prior to the date hereof, there not having occurred, in the Agent’s reasonable determination, except as disclosed in the SEC Reports, any material adverse change in the business, financial condition or operations of the Company and its subsidiaries, taken as a whole, since December 31, 2019; (iii) until the earlier of (A) a Successful Syndication and (B) the date that is 60 days after the Closing Date, without the Arranger’s prior written consent, there shall be no competing arrangement of any bank credit facility that is similar to, or a replacement of or substitution for the Facility by or on behalf of you or any of your subsidiaries, provided that the foregoing does not limit the ability of the Company or its subsidiaries to incur debt under any existing credit facilities or other debt programs in place as of the date hereof, or to issue commercial paper, equity or debt securities; and (iv) your written acceptance and compliance with the terms and conditions of the fee letter of even date herewith between the Company and the Wells Fargo Parties (the “Fee Letter”). As used herein, “SEC Reports” means (1) the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2019, (2) the Quarterly Reports on Form 10-Q of the Company for the fiscal quarters ended March 31, 2020, June 30, 2020 and September 30, 2020, and (3) the Current Reports on Form 8-K filed by the Company prior to the date hereof. Upon execution and delivery of the Credit Agreement, whether or not any loan or other extension of credit is made thereunder or any conditions of lending are met, the provisions of this paragraph shall be superseded by the provisions of the Credit Agreement.

The Company hereby agrees to reimburse the Agent and the Arranger for all reasonable out-of-pocket expenses (including the reasonable fees, time charges and expenses of attorneys for the Agent and the Arranger) and all reasonable out-of-pocket printing, reproduction, document delivery, travel, CUSIP, SyndTrak and communication costs incurred in connection with the due diligence, preparation, negotiation, execution, administration, syndication, distribution (including, without limitation, via the internet) and enforcement of this Commitment Letter, the Fee Letter, the Loan Documents and any other documentation contemplated hereby or thereby and the transactions contemplated hereby or thereby, whether incurred before or after the date of execution of this Commitment Letter and regardless of whether or not the transactions contemplated hereby are consummated.

Subject to the limitations on costs, fees and expenses set forth in the immediately preceding paragraph, the Company hereby further agrees to indemnify and hold harmless the Wells Fargo Parties and their respective affiliates, and their and their affiliates’ respective officers, employees, partners, representatives, advisors, agents and directors and each of their respective heirs, successors and assigns (each an “indemnified party”) against any and all actions, suits, losses, claims, damages, out-of-pocket


costs, fees and expenses (including the reasonable fees, time charges and expenses of attorneys for the indemnified parties, but limited to the reasonable and documented out-of-pocket fees, disbursements and other charges of one counsel to all indemnified parties (taken as a whole) and, if reasonably necessary, a single local counsel for all indemnified parties (taken as a whole) in each relevant jurisdiction and with respect to each relevant specialty, and in the case of an actual or perceived conflict of interest, one additional counsel in each relevant jurisdiction to the affected indemnified parties similarly situated and taken as a whole) and liabilities of every kind whatsoever (collectively, the “Indemnified Obligations”) to which each of the indemnified parties may become subject or that may be incurred or asserted or awarded against any indemnified party, in each case, arising out of or in connection with or by reason of (including, without limitation, in connection with any investigation, litigation or proceeding or preparation of a defense in connection therewith) (i) any matters contemplated by this Commitment Letter, the Fee Letter, the transactions contemplated hereby or any related transaction (including, without limitation, the execution and delivery of this Commitment Letter, the Loan Documents and the closing of the transactions) or (ii) the use or the contemplated use of the proceeds of the Facility, and will reimburse each indemnified party for all out of pocket expenses (including reasonable attorneys’ fees, expenses and charges) on demand as they are incurred in connection with any of the foregoing; provided that no indemnified party will have any right to indemnification for any Indemnified Obligation to the extent (x) resulting from such indemnified party’s own gross negligence, willful misconduct or material breach of the terms of this Commitment Letter (including the Term Sheet) or the Loan Documents by such indemnified party or (y) arising out of or resulting from claims of one or more indemnified parties against another indemnified party and not involving any act or omission of the Company or its or its affiliates’ officers, directors, employees or equityholders (other than (subject to clause (x) of this proviso) claims of indemnified parties against the Agent and/or the Arranger in their capacities as such), in each case, as determined by a final non-appealable judgment of a court of competent jurisdiction. In the case of an investigation, litigation or proceeding to which the indemnity in this paragraph applies, such indemnity shall be effective whether or not such investigation, litigation or proceeding is brought by you, your equityholders or creditors or an indemnified party, whether or not an indemnified party is otherwise a party thereto and whether or not the transactions contemplated hereby are consummated.

Without limiting the generality of the immediately preceding paragraph, you also agree that Wells Fargo Bank, the Arranger, each of their respective affiliates and each of their respective and their respective affiliates’ officers, employees, partners, representatives, advisors, agents and directors and each of their respective heirs, successors and assigns (such persons, collectively, the “Arranger Related Parties”) will not have any liability (whether direct or indirect, in contract or tort, or otherwise) to you or your affiliates or to your or their respective equityholders or creditors arising out of, related to or in connection with any aspect of the transactions contemplated hereby, except to the extent such liability is determined in a final, nonappealable judgment by a court of competent jurisdiction (i) to have resulted from such Arranger Related Party’s gross negligence, willful misconduct or material breach of the terms of this Commitment Letter (including the Term Sheet) or the Loan Documents by such Arranger Related Party or (ii) to have arisen out of or resulted from claims of one or more Arranger Related Parties against another Arranger Related Party and not involving any act or omission of the Company or its or its affiliates’ officers, directors, employees or equityholders. Except for the Company’s indemnification obligations set forth in the immediately preceding paragraph, no party hereto nor any of its affiliates nor any of such parties’ or affiliates’ respective officers, directors, employees, equityholders, representatives, advisors or agents (such affiliates and such officers, directors, employees, equityholders, representatives, advisors or agents of such party, being a “Representative” of such party) shall be liable under this Commitment Letter, the Fee Letter or any Loan Document or in respect of any act, omission or event relating to the transaction contemplated hereby or thereby, on any theory of liability, for any special, indirect, consequential or punitive damages. Except to the extent resulting from a breach of the confidentiality provisions hereof or from the gross negligence or willful misconduct of an Arranger Related Party, such Arranger Related Party will not be liable to you, your affiliates or any other person for


any damages arising from the use by others of Informational Materials (as defined below) or other materials properly disseminated by such Arranger Related Party by Electronic Means (as defined below).

The Company’s obligations and the parties’ agreements under the immediately preceding three paragraphs shall survive and are and shall remain absolute obligations of the Company and such other parties, whether or not Loan Documents are executed or any loan is made by the Lenders or any conditions of lending are met; provided that upon the execution and delivery of the Loan Documents, whether or not any loan or other extension of credit is made thereunder or any conditions of lending are met, such provisions shall be deemed superseded by the reimbursement, indemnity, exculpation and waiver of consequential damages provisions of the Loan Documents. The obligations of the Wells Fargo Parties under this Commitment Letter shall be enforceable solely by the Company and may not be relied upon by any other person. For purposes of this and the immediately preceding three paragraphs, the terms “Agent”, “Wells Fargo Bank” and “Arranger” shall include an affiliate of either.

The Company represents, warrants and covenants that (i) all written information (other than the Projections, as defined below) concerning the Company and its subsidiaries and the transactions contemplated hereby that has been or is hereafter made available to the Wells Fargo Parties or the Lenders by you, or any of your representatives, subsidiaries or affiliates (or on your or their behalf) (the “Information”) is, and in the case of Information made available after the date hereof, in each case, when furnished, (x) will be complete and correct in all material respects and (y) does not, and in the case of Information made available after the date hereof, will not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements contained therein, in light of the circumstances under which they were made, not materially misleading when taken as a whole and (ii) all financial projections and other forward-looking statements concerning the Company and its subsidiaries that have been or will be made available to the Wells Fargo Parties or the Lenders by the Company, or any of its representatives, subsidiaries or affiliates (or on the Company’s or their behalf) (the “Projections”) have been and will be prepared in good faith based upon assumptions believed by you to be reasonable at the time made (it being understood that such Projections are not to be viewed as facts and are subject to uncertainties and contingencies, many of which are beyond the Company’s control and that actual results may differ from the Projections and such differences may be material). As such, except as expressly set forth in the immediately preceding sentence, the Company makes no representation or warranty as to the Projections. The Company agrees to furnish the Wells Fargo Parties with such Information and Projections as they may reasonably request and to supplement, or cause to be supplemented, the Information and the Projections from time to time until the date the Loan Documents become effective in accordance with the provisions thereof (the “Closing Date”) so that the conditions and representations and warranties contained in the preceding sentence remain correct; it being agreed that such Information shall be deemed to have been provided by the Company as required hereunder upon the inclusion or disclosure thereof in any periodic or current report filed by the Company with the SEC. The Wells Fargo Parties will be entitled to use and rely upon, without responsibility to verify independently, the Information and, subject to the foregoing, the Projections.

The Company acknowledges that Wells Fargo Bank and the Arranger on the Company’s behalf will make available, on your behalf, the Information, Projections and other marketing materials and presentations, including confidential information memoranda (collectively, the “Informational Materials”), to the potential Lenders by posting the Informational Materials on SyndTrak Online or by other similar electronic means (collectively, the “Electronic Means”); provided that, at the request of the Arranger, you shall designate in any such disclosure whether such disclosure includes any material non-public or confidential information, and if so, the Arranger shall only provide such information to those Lenders or potential Lenders that have electronically confirmed or designated in writing that they are permitted for purposes of securities laws to receive such non-public or confidential information; all other such Lenders being hereinafter referred to as “Public Lenders.” Each of the Agent and the Arranger hereby agrees, and


the Arranger shall obtain the agreement of each Lender or prospective Lender to which it disseminates any non-public or confidential information regarding the Company or its affiliates, that it shall use such information only (i) in accordance with applicable law (including securities laws) and (ii) for purposes of evaluating the Facility, the transactions contemplated by this Commitment Letter, and the Term Sheet and shall otherwise comply with the other confidentiality provision herein (the “Use Restrictions”). Notwithstanding the foregoing, you agree that the Arranger may distribute the following documents to all prospective Lenders (including Public Lenders) on your behalf, unless you advise the Arranger in writing (including by email) within a reasonable time prior to their intended distributions that such material should not be distributed to Public Lenders: (w) administrative materials for prospective Lenders such as lender meeting invitations and funding and closing memoranda, (x) notifications of changes in the terms of the Facility, (y) financial information regarding the Company and its subsidiaries (other than the Projections) and (z) other materials intended for prospective Lenders after the initial distribution of the Informational Materials, including drafts and final versions of the Term Sheet and the Loan Documents. Before distribution of any Information Materials to prospective Lenders, the Company shall provide Wells Fargo Bank and the Arranger with a customary letter authorizing the dissemination of the Information Materials in accordance with this paragraph.

This Commitment Letter, the Fee Letter and the Term Sheet are for the Company’s confidential use only and may not be disclosed by it to any person other than (i) to its and its affiliates’ officers, directors, employees, attorneys and financial advisors (but not commercial lenders), and then only in connection with the proposed transaction and on a confidential basis, (ii) to any federal or state regulatory authority having jurisdiction over it or any of its affiliates, (iii) when (in the Company’s reasonable judgment) disclosure is required by law (including any securities law; provided that the Company shall seek confidential treatment of the Fee Letter if the Fee Letter (as distinguished from the disclosure of the aggregate fees payable thereunder) is required to be disclosed pursuant to any securities laws) or by any judicial, administrative or governmental body, agency or authority or by any order, writ, judgment, subpoena, decree or other compulsory legal mandate (in which case, you agree, to the extent permitted by law, regulatory authority or agency or court order or legal process, to inform us promptly in advance thereof), (iv) the Term Sheet may be disclosed to any ratings agency in connection with the Facility, (v) in any legal proceeding, arbitration, mediation or similar proceeding regarding any dispute concerning the terms hereof or thereof or the transactions contemplated hereby and thereby, (vi) the existence of this Commitment Letter and the Term Sheet, the amount of the Commitment, the identity of the Wells Fargo Parties and other terms and conditions of Facility may be disclosed by the Company to the public in its periodic securities filings, press releases or otherwise, so long as the terms and the conditions of the Fee Letter are treated as confidential in accordance with this paragraph, or (vii) where the Agent and the Arranger consent in writing to the proposed disclosure, which consent shall not be unreasonably withheld. Officers, directors, employees, attorneys and financial advisors of the Arranger, Wells Fargo Bank and the Agent and their affiliates shall at all times have the right to share amongst themselves in connection with this Commitment Letter, the Facility and the transactions contemplated thereby and on a confidential basis information received from the Company and its affiliates and their respective officers, directors, employees and agents. The Arranger reserves the right to assign some or all of its rights and delegate some or all of its responsibilities hereunder to one of its affiliates. This Commitment Letter, the Fee Letter, and the Term Sheet embody the entire agreement and understanding among the Wells Fargo Parties, you and your affiliates with respect to the subject matter hereof and supersede any and all prior versions hereof or thereof. This Commitment Letter may only be amended by a writing signed by all parties hereto. This Commitment Letter is not assignable by you without the Arranger’s prior written consent.

Each of Agent and the Arranger, at their respective sole expense, may publish customary marketing tombstones advertisements as comply with applicable federal laws relating to the Facility; provided that the Company shall have the right to review and approve all such advertisements (such


approval not to be unreasonably withheld or delayed). The foregoing authorization shall remain in effect unless the Company notifies Agent and Arranger in writing that such authorization is revoked. Each of Agent and the Arranger shall be permitted to use information related to the syndication and arrangement of the Facility (i) customarily required in connection with obtaining a CUSIP number and (ii) routinely provided by arrangers to data service providers, including league table providers, that serve the lending industry.

Each of the Agent and the Arranger agrees to keep confidential, and not disclose, any information not otherwise publicly available that it obtains about the Company and/or its affiliates, the Company’s and/or its affiliates’ books and records, or the Company’s and/or its affiliates properties, results, products, prospects, customers, operations or condition (financial or otherwise), except that the Agent and the Arranger may disclose such information (i) as required by applicable law, (ii) to its attorneys, auditors, accountants and other professional advisors in connection with the Facility and the transactions contemplated thereby, who have been informed as to the confidential nature of such information, (iii) in connection with the enforcement of the Loan Documents, (iv) to any Lender, potential Lender, transferee or potential transferee in connection with its syndication activities contemplated hereby or as permitted by the Loan Documents, provided that the disclosure of any such information to such Lender, potential Lender, transferee or potential transferee shall be made subject to the acknowledgment and acceptance by such Lender or prospective Lender or participant or prospective participant that such information is being disseminated on a confidential basis (on substantially the terms set forth in this paragraph or as is otherwise reasonably acceptable to you and the Arranger, including, without limitation, as agreed in any confidential information memorandum or other marketing materials) in accordance with the standard syndication processes of the Arranger or customary market standards for dissemination of such type of information, (v) to any federal or state banking authority or other regulatory authority having jurisdiction over it or any of its affiliates, (vi) to any of its respective affiliates solely in connection with the Facility (and you acknowledge that such affiliates may share with Wells Fargo Bank or Arranger, any information related to you or any of your subsidiaries or affiliates (including, without limitation, in each case, information relating to creditworthiness) and the transactions contemplated hereby) and (vii) to any of its officers, employees and agents which have been informed as to the confidential nature of such information in connection with the proposed transaction; provided that in the cases of clauses (i) and (iii) above, such disclosing party shall (x) provide the Company with reasonable advance notice of such disclosure to the extent legally permitted and practicable to do so to permit the Company to limit the scope of or to contest the need for such disclosure and (y) use commercially reasonable efforts to limit such disclosure to only that portion of the confidential information required to be disclosed. Each of the Agent, Wells Fargo Bank and the Arranger acknowledge and agree that money damages may not be a sufficient remedy for violations by any of the foregoing of the confidentiality or Use Restrictions set forth herein and, as such, the Company shall be entitled to seek equitable relief, including injunctive relief, without proof of actual damages. The provisions of this paragraph shall survive and are and shall remain absolute obligations of the Agent and the Arranger whether or not Loan Documents are executed or any loan is made by the Lenders or any conditions of lending are met, provided that (1) such agreements and undertakings under this paragraph shall automatically terminate eighteen months following the date of this Commitment Letter and (2) notwithstanding the foregoing, upon execution, delivery and effectiveness of the Credit Agreement, whether or not any loan or other extension of credit is made thereunder or any conditions of lending are met, the provisions of this paragraph shall be superseded by the provisions of the Credit Agreement. Each of the Agent and the Arranger shall be liable for the breach of any of the disclosure restrictions or Use Restrictions herein by any of its Representatives.

Each of the Wells Fargo Parties hereby notify you that pursuant to the requirements of the USA Patriot Act, Title III of Pub. L. 107-56 (signed into law October 26, 2001) (the “Patriot Act”), each of them is required to obtain, verify and record information that identifies you, which information includes


your name and address and other information that will allow the Wells Fargo Parties and the other Lenders to identify you in accordance with the Patriot Act.

Nothing contained herein shall limit or preclude the Agent, Wells Fargo Bank, the Arranger or any of their respective affiliates from carrying on any business with, providing banking or other financial services to, or from participating in any capacity, including as an equity investor, in any party whatsoever, including, without limitation, any competitor, supplier or customer of you or any of your affiliates, or any other party that may have interests different than or adverse to such parties.

You acknowledge that the Arranger and its affiliates (i) may be providing debt financing, equity capital or other services (including financial advisory services) to other entities and persons with which you or your affiliates may have conflicting interests regarding the transactions contemplated hereby and by the Term Sheet and otherwise, (ii) so long as not in violation of its contractual obligations to you, may act as it deems appropriate with respect to such other entities or persons, and (iii) have no obligation in connection with the transactions contemplated hereby to use, or to furnish to you or your affiliates or subsidiaries, confidential information obtained from other entities or persons. In connection with the foregoing, the Arranger and its affiliates will not use confidential information obtained from you by virtue of the Facility or their other relationships with you in connection with the performance by them of services for other companies, and none of the Arranger, Wells Fargo Bank, the Agent or any of foregoing’s affiliates will furnish any such information to such other companies.

In connection with all aspects of the transactions contemplated hereby, you acknowledge and agree that: (i) the Facility and any related arranging or other services described in this Commitment Letter is an arm’s-length commercial transaction between you and your affiliates, on the one hand, and the Agent, Wells Fargo Bank and the Arranger (collectively, the “Commitment Parties”), on the other hand, and you are capable of evaluating and understanding and understand and accept the terms, risks and conditions of the transactions contemplated hereby, (ii) in connection with the process leading to the transactions contemplated hereby, except and to the extent as may otherwise be expressly agreed in a separate writing, each of the Commitment Parties are and have been acting solely as a principal and not as a financial advisor, agent or fiduciary, for you or any of your affiliates, equityholders, directors, officers, employees, creditors or any other party, (iii) except and to the extent as may otherwise be expressly agreed in a separate writing, (x) no Commitment Party has assumed or will assume an advisory, agency or fiduciary responsibility in your or your affiliates’ favor with respect to any of the transactions contemplated hereby or the process leading thereto (irrespective of whether any Commitment Party has advised or is currently advising you or your affiliates on other matters) and (y) no Commitment Party has any obligation to you or your affiliates with respect to the transactions contemplated hereby except those obligations expressly set forth in this Commitment Letter, the Term Sheet and the Fee Letter, (iv) the Commitment Parties and their respective affiliates may be engaged in a broad range of transactions that involve interests that differ from yours and your affiliates and no Commitment Party shall have any obligation to disclose any of such interests, and (v) no Commitment Party has provided any legal, accounting, regulatory or tax advice with respect to any of the transactions contemplated hereby and you have consulted your own legal, accounting, regulatory and tax advisors to the extent you have deemed appropriate. You hereby waive and release, to the fullest extent permitted by law, any claims that you may have against any Commitment Party with respect to any breach or alleged breach of agency, fiduciary duty or actual or potential conflict of interest.

The foregoing three paragraphs shall survive any termination or expiration of this Commitment Letter or the Commitment of Wells Fargo Bank or the undertakings of the Arranger set forth herein (regardless of whether definitive Loan Documents are executed and delivered).



Please indicate the Company’s acceptance of the commitment herein contained in the space indicated below and return a copy of this Commitment Letter so executed to the Arranger. By its acceptance hereof, the Company agrees to pay the Agent, Wells Fargo Bank and the Arranger the fees described in the Term Sheet and the Fee Letter subject to and in accordance with the terms thereof, and agrees that Wells Fargo Bank’s commitment is conditioned upon the Company’s compliance with all of the provisions of the Fee Letter. This commitment will expire at 5:00 p.m. (Eastern Standard Time) on February 24, 2021, unless on or prior to such time the Arranger shall have received a copy of this Commitment Letter and the Fee Letter, each executed by the Company. Notwithstanding timely acceptance of this Commitment Letter pursuant to the preceding sentence, the commitment herein contained will automatically terminate unless definitive Loan Documents are executed on or before April 8, 2021.

THIS COMMITMENT LETTER AND THE FEE LETTER, AND ANY CLAIM, CONTROVERSY OR DISPUTE ARISING UNDER OR RELATED THERETO (INCLUDING, WITHOUT LIMITATION, ANY CLAIMS SOUNDING IN CONTRACT LAW OR TORT LAW ARISING OUT OF THE SUBJECT MATTER HEREOF OR THEREOF), SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK (INCLUDING SECTION 5-1401 AND SECTION 5-1402 OF THE GENERAL OBLIGATIONS LAW OF THE STATE OF NEW YORK), WITHOUT REFERENCE TO ANY OTHER CONFLICTS OR CHOICE OF LAW PRINCIPLES THEREOF. THE PARTIES HEREBY WAIVE ANY RIGHT TO TRIAL BY JURY WITH RESPECT TO ANY CLAIM OR ACTION ARISING OUT OF THIS COMMITMENT LETTER OR THE FEE LETTER. With respect to any suit, action or proceeding arising in respect of this Commitment Letter or the Fee Letter or any of the matters contemplated hereby or thereby, the parties hereto hereby irrevocably and unconditionally submit to the exclusive jurisdiction of any state or federal court located in the Borough of Manhattan, and irrevocably and unconditionally waive any objection to the laying of venue of such suit, action or proceeding brought in such court and any claim that such suit, action or proceeding has been brought in an inconvenient forum. The parties hereto hereby agree that service of any process, summons, notice or document by registered mail addressed to you or each of the Commitment Parties will be effective service of process against such party for any action or proceeding relating to any such dispute. A final judgment in any such action or proceeding may be enforced in any other courts with jurisdiction over you or each of the Commitment Parties. No person has been authorized by any of the Commitment Parties to make any oral or written statements inconsistent with this Commitment Letter or the Fee Letter. This Commitment Letter and the Fee Letter are not intended to benefit or create any rights in favor of any person other than the parties hereto, the Lenders and, with respect to indemnification, each indemnified party, and with respect to exculpation, the Arranger Related Parties. This Commitment Letter and the Fee Letter may be executed in separate counterparts, which taken together shall constitute an original. Delivery of an executed signature page of this Commitment Letter and the Fee Letter by facsimile or electronic mail shall be effective as delivery of manually executed counterpart hereof. The execution and delivery of this Commitment Letter shall be deemed to include electronic signatures on electronic platforms approved by the Arranger, which shall be of the same legal effect, validity or enforceability as delivery of a manually executed signature, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act; provided that, upon the request of any party hereto, such electronic signature shall be promptly followed by the original thereof.

[Signature Page Follows]




Sincerely,

WELLS FARGO BANK, NATIONAL ASSOCIATION

By: /s/ Patrick Engel
Name: Patrick Engel
Title: Managing Director

WELLS FARGO SECURITIES, LLC

By: /s/ Michael E. McDuffie
Name: Michael E. McDuffie
Title: Managing Director

ACCEPTED AND AGREED TO
AS OF FEBRUARY 24, 2021:

OGE ENERGY CORP.


By: /s/ Charles B. Walworth
Name: Charles B. Walworth
Title: Treasurer


Exhibit 21.01

OGE Energy Corp.
Subsidiaries of the Registrant

Name of Subsidiary Jurisdiction of Incorporation
Percentage of
Ownership
Oklahoma Gas and Electric Company Oklahoma 100.0
OGE Enogex Holdings LLC Delaware 100.0

The above listed subsidiaries have been consolidated in the Registrant's financial statements. Certain of the Company's subsidiaries have been omitted from the list above in accordance with Rule 1-02(w) of Regulation S-X.



Exhibit 23.01

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-92423) pertaining to the deferred compensation plan, the Registration Statement (Form S-8 No. 333-104497) pertaining to the employees' stock ownership and retirement savings plan, Registration Statement (Form S-8 No. 333-190406) pertaining to the employees' stock ownership and retirement savings plan, Registration Statement (Form S-8 No. 333-190405) pertaining to the 2013 stock incentive plan, the Registration Statement (Form S-3ASR No. 333-249236) pertaining to the dividend reinvestment and stock purchase plan and the Registration Statement (Form S-3ASR No. 333-225030) pertaining to common stock and debt securities of our reports dated February 24, 2021, with respect to the consolidated financial statements and schedule of OGE Energy Corp. and the effectiveness of internal control over financial reporting of OGE Energy Corp. included in this Annual Report (Form 10-K) for the year ended December 31, 2020.

/s/  Ernst & Young LLP


Oklahoma City, Oklahoma
February 24, 2021



Exhibit 23.02

Consent of Independent Registered Public Accounting Firm


We consent to the incorporation by reference in the Registration Statement (Form S-3ASR No. 333-225030-01) pertaining to debt securities of our reports dated February 24, 2021, with respect to the financial statements and schedule of Oklahoma Gas and Electric Company and the effectiveness of internal control over financial reporting of Oklahoma Gas and Electric Company included in this Annual Report (Form 10-K) for the year ended December 31, 2020.

/s/  Ernst & Young LLP


Oklahoma City, Oklahoma
February 24, 2021



Exhibit 23.03

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-92423, 333-104497, 333-190406, and 333-190405 on Form S-8; Registration Statement Nos. 333-225030, and 333-249236 on Form S-3ASR of our report dated February 24, 2021 relating to the consolidated financial statements of Enable Midstream Partners, LP and subsidiaries appearing in this Annual Report on Form 10-K of OGE Energy Corp. for the year ended December 31, 2020.

/s/ DELOITTE & TOUCHE LLP
Oklahoma City, Oklahoma
February 24, 2021



Exhibit 24.01

Power of Attorney


WHEREAS, OGE ENERGY CORP., an Oklahoma corporation (herein referred to as the "Company"), is about to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 2020; and

WHEREAS, each of the undersigned holds the office or offices in the Company herein-below set opposite his or her name, respectively;

NOW, THEREFORE, each of the undersigned hereby constitutes and appoints SEAN TRAUSCHKE, W. BRYAN BUCKLER and SARAH R. STAFFORD and each of them individually, his or her attorney with full power to act for him or her and in his or her name, place and stead, to sign his or her name in the capacity or capacities set forth below to said Form 10-K and to any and all amendments thereto, and hereby ratifies and confirms all that said attorney may or shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 24th day of February, 2020.
Sean Trauschke, Chairman, Principal
Executive Officer and Director 		/s/ Sean Trauschke
Frank A. Bozich, Director /s/ Frank A. Bozich
James H. Brandi, Director /s/ James H. Brandi
Peter D. Clarke, Director /s/ Peter D. Clarke
Luke R. Corbett, Director /s/ Luke R. Corbett
David L. Hauser, Director /s/ David L. Hauser
Luther C. Kissam, IV /s/ Luther C. Kissam, IV
Judy R. McReynolds, Director /s/ Judy R. McReynolds
David E. Rainbolt, Director /s/ David E. Rainbolt
J. Michael Sanner, Director /s/ J. Michael Sanner
Sheila G. Talton, Director /s/ Sheila G. Talton
W. Bryan Buckler, Principal Financial
Officer 		/s/ W. Bryan Buckler
Sarah R. Stafford, Principal Accounting
Officer 		/s/ Sarah R. Stafford
STATE OF OKLAHOMA )
) SS
COUNTY OF OKLAHOMA )

On the date indicated above, before me, Kelly Hamilton-Coyer, Notary Public in and for said County and State, the above named directors and officers of OGE ENERGY CORP., an Oklahoma corporation, known to me to be the persons whose names are subscribed to the foregoing instrument, severally acknowledged to me that they executed the same as their own free act and deed.


IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal on the 24th day of February, 2020.

/s/ Kelly Hamilton-Coyer
By: Kelly Hamilton-Coyer
Notary Public
My commission expires:
July 6, 2021


Exhibit 24.02

Power of Attorney

WHEREAS, OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation (herein referred to as the "Company"), is about to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 2020; and

WHEREAS, each of the undersigned holds the office or offices in the Company herein-below set opposite his or her name, respectively;

NOW, THEREFORE, each of the undersigned hereby constitutes and appoints SEAN TRAUSCHKE, W. BRYAN BUCKLER and SARAH R. STAFFORD and each of them individually, his or her attorney with full power to act for him or her and in his or her name, place and stead, to sign his or her name in the capacity or capacities set forth below to said Form 10-K and to any and all amendments thereto, and hereby ratifies and confirms all that said attorney may or shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 24th day of February, 2021.
Sean Trauschke, Chairman, Principal
Executive Officer and Director 		/s/ Sean Trauschke
Frank A. Bozich, Director /s/ Frank A. Bozich
James H. Brandi, Director /s/ James H. Brandi
Peter D. Clarke, Director /s/ Peter D. Clarke
Luke R. Corbett, Director /s/ Luke R. Corbett
David L. Hauser, Director /s/ David L. Hauser
Luther C. Kissam, IV /s/ Luther C. Kissam, IV
Judy R. McReynolds, Director /s/ Judy R. McReynolds
David E. Rainbolt, Director /s/ David E. Rainbolt
J. Michael Sanner, Director /s/ J. Michael Sanner
Sheila G. Talton, Director /s/ Sheila G. Talton
W. Bryan Buckler, Principal Financial
Officer 		/s/ W. Bryan Buckler
Sarah R. Stafford, Principal Accounting
  Officer
/s/ Sarah R. Stafford
STATE OF OKLAHOMA )
) SS
COUNTY OF OKLAHOMA )

On the date indicated above, before me, Kelly Hamilton-Coyer, Notary Public in and for said County and State, the above named directors and officers of OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation, known to me to be the persons whose names are subscribed to the foregoing instrument, severally acknowledged to me that they executed the same as their own free act and deed.

IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal on the 24th day of February, 2021.

/s/ Kelly Hamilton-Coyer
By: Kelly Hamilton-Coyer
Notary Public

My commission expires:
July 6, 2021



Exhibit 31.01

CERTIFICATIONS
I, Sean Trauschke, certify that:
1. I have reviewed this annual report on Form 10-K of OGE Energy Corp.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 24, 2021
  /s/ Sean Trauschke  
Sean Trauschke  
Chairman of the Board, President and Chief Executive Officer



Exhibit 31.01

CERTIFICATIONS
I, W. Bryan Buckler, certify that:
1. I have reviewed this annual report on Form 10-K of OGE Energy Corp.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 24, 2021
  /s/ W. Bryan Buckler  
W. Bryan Buckler  
Chief Financial Officer



Exhibit 31.02

CERTIFICATIONS
I, Sean Trauschke, certify that:
1. I have reviewed this annual report on Form 10-K of Oklahoma Gas and Electric Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 24, 2021
  /s/ Sean Trauschke  
Sean Trauschke  
Chairman of the Board, President and Chief Executive Officer





Exhibit 31.02

CERTIFICATIONS
I, W. Bryan Buckler, certify that:
1. I have reviewed this annual report on Form 10-K of Oklahoma Gas and Electric Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 24, 2021
  /s/ W. Bryan Buckler  
W. Bryan Buckler  
Chief Financial Officer




Exhibit 32.01

Certification Pursuant to 18 U.S.C. Section 1350
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


In connection with the Annual Report of OGE Energy Corp. ("OGE Energy") on Form 10-K for the year ended December 31, 2020, as filed with the Securities and Exchange Commission (the "Report"), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of OGE Energy.

February 24, 2021


            /s/ Sean Trauschke  
                 Sean Trauschke  
Chairman of the Board, President and Chief Executive Officer

            /s/ W. Bryan Buckler  
                 W. Bryan Buckler  
Chief Financial Officer





Exhibit 32.02

Certification Pursuant to 18 U.S.C. Section 1350
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


In connection with the Annual Report of Oklahoma Gas and Electric Company ("OG&E") on Form 10-K for the year ended December 31, 2020, as filed with the Securities and Exchange Commission (the "Report"), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of OG&E.

February 24, 2021


            /s/ Sean Trauschke  
                 Sean Trauschke  
Chairman of the Board, President and Chief Executive Officer

            /s/ W. Bryan Buckler  
                 W. Bryan Buckler  
Chief Financial Officer


Exhibit 99.01
Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Enable GP, LLC and
Unitholders of Enable Midstream Partners, LP
Oklahoma City, Oklahoma

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Enable Midstream Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, cash flows and partners' equity, for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2021, expressed an unqualified opinion on the Partnership's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Exhibit 99.01
Evaluation of the estimated undiscounted cash flows in the long-lived assets impairment analysis - Refer to Notes 1 and 8 to the consolidated financial statements

Critical Audit Matter Description

The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets.

Due to decreases in natural gas and NGL market prices during 2020 as a result of the ongoing COVID-19 pandemic and the economic effects of the pandemic, together with the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, events or changes in circumstances indicated that the carrying value of certain assets groups in the Gathering & Processing (“G&P”) segment may not be recoverable. The net book value of the G&P asset groups was $7,470 million as of December 31, 2020. The Partnership recognized a $16 million impairment during the year ended December 31, 2020.

Given the significant judgments made by management to estimate the recoverability of G&P asset groups, performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to forecasts of future revenues, including the revenue growth rate, of G&P asset groups required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the forecasts of future revenues, including the revenue growth rate, used by management to estimate the recoverability of G&P asset groups included the following, among others:
•We tested the effectiveness of controls over management’s long-lived assets impairment evaluation, including those over the determination of the recoverability of G&P asset groups, such as controls related to management’s forecasts of future revenues, including the revenue growth rate.
•We evaluated management’s ability to accurately forecast future revenues by comparing actual results to management’s historical forecasts.
•We evaluated the reasonableness of management’s revenue forecasts by comparing the forecasts to:
–Agreements in place between the Partnership and current customers for G&P asset groups.
–Historical revenues.
–Internal communications to management and the Board of Directors.
–Forecasted information included in Partnership press releases as well as in analyst and industry reports for the Partnership and certain of its peer companies.
•With the assistance of our fair value specialists, we evaluated the reasonableness of the revenue growth rate by:
–Testing the source information underlying the determination of the revenue growth rate and the mathematical accuracy of the calculation.
–Developing a range of independent estimates and comparing those to the revenue growth rate selected by management.

Other-Than-Temporary-Impairment (“OTTI”) of the Southeast Supply Header, LLC (“SESH”) equity method investment - Refer to Notes 1 and 11 to the consolidated financial statements

Critical Audit Matter Description

SESH is an approximately 290-mile interstate pipeline that provides transportation services in Louisiana, Mississippi and Alabama. The Partnership own a 50% interest in SESH and provides field operations for the pipeline. Enbridge Inc. owns the remaining 50% interest in SESH and provides gas control and commercial operations for the pipeline.

The Partnership evaluates its investment in equity method affiliate for impairment when factors indicate that an other than temporary decrease in the fair value of its investment has occurred and the fair value of its investment is less than the carrying amount.


Exhibit 99.01
During the third quarter of 2020, due to the expiration of a transportation contract and the current status of renewal negotiations, the Partnership evaluated its equity method investment in SESH for other-than-temporary impairment. The Partnership utilized the market and income approaches to measure the estimated fair value of its investment in SESH. The Partnership determined the decline in value of its investment in SESH was other-than-temporary, and recorded an impairment of its investment in SESH of $225 million.

Given the significant judgments made by management to estimate the fair value of SESH, performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to forecasts of future revenues, including the revenue growth rate, and the selection of the weighted average cost of capital and market multiple of SESH required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the weighted average cost of capital, market multiple, and forecasts of future revenues, including the revenue growth rate, used by management to estimate the fair value of SESH included the following, among others:
•We tested the effectiveness of controls over management’s equity method investment impairment evaluation, including those over the determination of the fair value of SESH, such as controls related to management’s forecasts of future revenues, including the revenue growth rate, and selection of the weighted average cost of capital and market multiple.
•We evaluated management’s ability to accurately forecast future revenues by comparing actual results to management’s historical forecasts.
•We evaluated the reasonableness of management’s revenue forecasts by comparing the forecasts to:
–Agreements in place between SESH and current customers.
–Historical revenues.
–Internal communications to management and the Board of Directors.
•With the assistance of our fair value specialists, we evaluated the reasonableness of the (1) valuation methodology and (2) weighted average cost of capital, market multiple, and revenue growth rate by:
–Testing the source information underlying the determination of the weighted average cost of capital, market multiple, and revenue growth rate and the mathematical accuracy of the calculations.
–Developing a range of independent estimates and comparing those to the weighted average cost of capital, market multiple, and revenue growth rate selected by management.

/s/ DELOITTE & TOUCHE LLP

Oklahoma City, Oklahoma
February 24, 2021

We have served as the Partnership's auditor since 2013.


Exhibit 99.01
ENABLE MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF INCOME
 
  Year Ended December 31,
  2020 2019 2018
  (In millions, except per unit data)
Revenues (including revenues from affiliates (Note 16)):
Product sales $ 1,132  $ 1,533  $ 2,106 
Service revenues 1,331  1,427  1,325 
Total Revenues 2,463  2,960  3,431 
Cost and Expenses (including expenses from affiliates (Note 16)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
965  1,279  1,819 
Operation and maintenance 418  423  388 
General and administrative 98  103  113 
Depreciation and amortization 420  433  398 
Impairments of property, plant and equipment and goodwill (Notes 8 and 10) 28  86  — 
Taxes other than income tax 69  67  65 
Total Cost and Expenses 1,998  2,391  2,783 
Operating Income 465  569  648 
Other Income (Expense):
Interest expense (178) (190) (152)
Equity in earnings (losses) of equity method affiliate, net (210) 17  26 
Other, net 6  3  — 
Total Other Expense (382) (170) (126)
Income Before Income Tax 83  399  522 
Income tax benefit —  (1) (1)
Net Income $ 83  $ 400  $ 523 
Less: Net income (loss) attributable to noncontrolling interests (5) 4  2 
Net Income Attributable to Limited Partners $ 88  $ 396  $ 521 
Less: Series A Preferred Unit distributions (Note 7) 36  36  36 
Net Income Attributable to Common Units (Note 6) $ 52  $ 360  $ 485 
Basic and diluted earnings per common unit (Note 6)
Basic $ 0.12  $ 0.83  $ 1.12 
Diluted $ 0.12  $ 0.82  $ 1.11 

 

See Notes to the Consolidated Financial Statements
4
Exhibit 99.01
ENABLE MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 
  Year Ended December 31,
  2020 2019 2018
  (In millions)
Net income $ 83  $ 400  $ 523 
Other comprehensive loss:
Change in fair value of interest rate derivative instruments (7) (3) — 
Reclassification of interest rate derivative losses to net income 4  —  — 
Other comprehensive loss (3) (3) — 
Comprehensive income 80  397  523 
Less: Comprehensive income (loss) attributable to noncontrolling interests (5) 4  2 
Comprehensive income attributable to Limited Partners
$ 85  $ 393  $ 521 

See Notes to the Consolidated Financial Statements
5
Exhibit 99.01
ENABLE MIDSTREAM PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
December 31,
2020 2019
  (In millions, except units)
Current Assets:
Cash and cash equivalents $ 3  $ 4 
Accounts receivable, net of allowance for doubtful accounts (Note 1) 248  244 
Accounts receivable—affiliated companies 15  25 
Inventory 42  46 
Gas imbalances 42  35 
Other current assets 31  35 
Total current assets 381  389 
Property, Plant and Equipment:
Property, plant and equipment 13,220  13,161 
Less accumulated depreciation and amortization 2,555  2,291 
Property, plant and equipment, net 10,665  10,870 
Other Assets:
Intangible assets, net 539  601 
Goodwill —  12 
Investment in equity method affiliate 76  309 
Other 68  85 
Total other assets 683  1,007 
Total Assets $ 11,729  $ 12,266 
Current Liabilities:
Accounts payable $ 149  $ 161 
Accounts payable—affiliated companies 2  1 
Short-term debt 250  155 
Current portion of long-term debt —  251 
Taxes accrued 34  32 
Gas imbalances 19  19 
Accrued compensation 43  31 
Customer deposits 18  17 
Other 67  113 
Total current liabilities 582  780 
Other Liabilities:
Accumulated deferred income tax, net 5  4 
Regulatory liabilities 25  24 
Other 71  80 
Total other liabilities 101  108 
Long-Term Debt 3,951  3,969 
Commitments and Contingencies (Note 17)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at December 31, 2020 and December 31, 2019, respectively)
362  362 
Common Units (435,549,892 issued and outstanding at December 31, 2020 and 435,201,365 issued and outstanding at December 31, 2019)
6,713  7,013 
Accumulated other comprehensive loss (6) (3)
Noncontrolling interests 26  37 
Total Partners’ Equity 7,095  7,409 
Total Liabilities and Partners’ Equity $ 11,729  $ 12,266 
See Notes to the Consolidated Financial Statements
6
Exhibit 99.01
ENABLE MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
  Year Ended December 31,
  2020 2019 2018
  (In millions)
Cash Flows from Operating Activities:
Net income $ 83  $ 400  $ 523 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 420  433  398 
Deferred income tax 1  (1) (1)
Impairments of property, plant and equipment and goodwill 28  86  — 
Net loss on sale/retirement of assets 24  8  1 
Gain on extinguishment of debt (5) —  — 
Equity in (earnings) losses of equity method affiliate, net 210  (17) (26)
Return on investment in equity method affiliate 15  17  26 
Equity-based compensation 13  16  16 
Amortization of debt costs and discount (premium) 4  (1) (1)
Changes in other assets and liabilities:
Accounts receivable, net (5) 43  (10)
Accounts receivable—affiliated companies 10  (6) (1)
Inventory 4  4  (10)
Gas imbalance assets (7) (6) 8 
Other current assets 3  9  (21)
Other assets 5  11  (12)
Accounts payable (10) (75) 4 
Accounts payable—affiliated companies 1  (3) 1 
Gas imbalance liabilities —  (3) 10 
Other current liabilities (32) 39  4 
Other liabilities (5) (12) 15 
Net cash provided by operating activities 757  942  924 
Cash Flows from Investing Activities:
Capital expenditures (215) (432) (728)
Acquisitions, net of cash acquired —  —  (443)
Proceeds from sale of assets 20  1  8 
Proceeds from insurance 1  1  2 
Return of investment in equity method affiliate 8  8  7 
Other, net 4  (8) — 
Net cash used in investing activities (182) (430) (1,154)
Cash Flows from Financing Activities:
Increase (decrease) increase in short-term debt 95  (494) 244 
Proceeds from long-term debt, net of issuance costs —  1,544  787 
Repayment of long-term debt (267) (700) (450)
Proceeds from Revolving Credit Facility 869  —  350 
Repayment of Revolving Credit Facility (869) (250) (100)
Proceeds from issuance of common units, net of issuance costs —  —  2 
Distributions to common unitholders (360) (564) (551)
Distributions to preferred unitholders (36) (36) (36)
Distributions to non-controlling interests (6) (5) (4)
Cash paid for employee equity-based compensation (2) (25) (9)
Net cash (used in) provided by financing activities (576) (530) 233 
Net (Decrease) Increase in Cash and Cash Equivalents (1) (18) 3 
Cash and Cash Equivalents at Beginning of Period 4  22  19 
Cash and Cash Equivalents at End of Period $ 3  $ 4  $ 22 
See Notes to the Consolidated Financial Statements
7
Exhibit 99.01
ENABLE MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY
  Series A Preferred Units Common Units Accumulated Other Comprehensive Earnings Noncontrolling
Interest 		Total
Partners’
Equity
  Units Value Units Value Value Value Value
(In millions)
Balance as of December 31, 2017 15  $ 362  433  $ 7,280  $ —  $ 12  $ 7,654 
Net income —  36  —  485  —  2  523 
Issuance of common units —  —  —  2  —  —  2 
Acquisition of EOCS
—  —  —  —  —  28  28 
Distributions —  (36) —  (551) —  (4) (591)
Equity-based compensation, net of units for employee taxes
—  —  —  2  —  —  2 
Balance as of December 31, 2018 15  $ 362  433  $ 7,218  $ —  $ 38  $ 7,618 
Net income —  36  —  360  —  4  400 
Other comprehensive loss —  —  —  —  (3) —  (3)
Distributions
—  (36) —  (564) —  (5) (605)
Equity-based compensation, net of units for employee taxes
—  —  2  (1) —  —  (1)
Balance as of December 31, 2019 15  $ 362  435  $ 7,013  $ (3) $ 37  $ 7,409 
Net income (loss) —  36  —  52  —  (5) 83 
Other comprehensive loss —  —  —  —  (3) —  (3)
Distributions —  (36) —  (360) —  (6) (402)
Equity-based compensation, net of units for employee taxes
—  —  —  11  —  —  11 
Impact of adoption of financial instruments-credit losses accounting standard (Note 1) —  —  —  (3) —  —  (3)
Balance as of December 31, 2020 15  $ 362  435  $ 6,713  $ (6) $ 26  $ 7,095 
See Notes to the Consolidated Financial Statements
8
Exhibit 99.01
ENABLE MIDSTREAM PARTNERS, LP
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
 
(1) Summary of Significant Accounting Policies

Organization

Enable Midstream Partners, LP (the Partnership) is a Delaware limited partnership formed on May 1, 2013. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. Our transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers. Our natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Our crude oil gathering assets are located in Oklahoma and North Dakota and serve crude oil production in the Anadarko and Williston Basins. Our natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma and our investment in SESH, a pipeline extending from Louisiana to Alabama.

CenterPoint Energy and OGE Energy each have 50% of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP.

At December 31, 2020, CenterPoint Energy held approximately 53.7% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.5% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 7 for further information related to the Series A Preferred Units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect Enable GP on an annual or continuing basis and may not remove Enable GP without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class.

For the years ended December 31, 2020, 2019 and 2018, the Partnership owned a 50% interest in SESH. See Note 11 for further discussion of SESH. For the years ended December 31, 2020, 2019 and 2018, the Partnership owned a 50% ownership interest in Atoka and consolidated Atoka in the accompanying Consolidated Financial Statements as EOIT acted as the managing member of Atoka and had control over the operations of Atoka. In addition, for the period of November 1, 2018 through December 31, 2020, the Partnership owned a 60% interest in ESCP, which is consolidated in the accompanying Consolidated Financial Statements as EOCS acted as the managing member of ESCP and had control over the operations of ESCP.

Basis of Presentation

The accompanying Consolidated Financial Statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP.

For a description of the Partnership’s reportable segments, see Note 20.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

9
Exhibit 99.01
Revenue Recognition

The Partnership generates the majority of its revenues from midstream energy services, including natural gas gathering, processing, transportation and storage and crude oil, condensate and produced water gathering. The Partnership performs these services under various contractual arrangements, which include fee-based contract arrangements and arrangements pursuant to which it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. The Partnership reflects revenue as Product sales and Service revenues on the Consolidated Statements of Income as follows:

Product sales: Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and used in connection with providing the Partnership’s midstream services.

Service revenues: Service revenues represent all other revenue generated as a result of performing the Partnership’s midstream services.

The Partnership recognizes revenue from natural gas gathering, processing, transportation and storage and crude oil, condensate and water gathering services to third parties in accordance with ASU No. 2014-09 “Revenue from Contracts with Customers” (Topic 606). Under Topic 606, revenue is recognized at an amount that reflects the consideration to which the entity expects to be entitled in exchange for transferring goods or services. The determination of that amount and the timing of recognition is based on identifying the contracts with customers, identifying the performance obligations in the contract, determining the transaction price, allocating the transaction price to the performance obligations in the contract, and ultimately recognizing revenue when (or as) the entity satisfies the performance obligation.

Service revenues for gathering, processing, transportation and storage services for the Partnership are recorded each month as services have been completed and performance obligations are met. Product revenues are recognized when control is transferred. Monthly revenues are based on the current month’s estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on the current month’s nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on the current month’s estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated revenues are reflected in Accounts receivable, net or Accounts receivable—affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Total revenues on the Consolidated Statements of Income.

The Partnership records deferred revenue when it receives consideration from a third party before achieving certain criteria that must be met for revenue to be recognized in accordance with GAAP.

The Partnership relies on certain key natural gas producer customers for a significant portion of natural gas and NGLs supply. The Partnership relies on certain key utilities for a significant portion of transportation and storage demand. The Partnership depends on third-party facilities to transport and fractionate NGLs that it delivers to third parties at the inlet of their facilities. For the year ended December 31, 2020, one non-affiliate customer accounted for approximately 13%, or $310 million of our consolidated revenue. For the year ended December 31, 2019, one non-affiliate customer accounted for approximately 11%, or $328 million of our consolidated revenue. These revenues were primarily included in our gathering and processing segment. There are no revenue concentrations with individual non-affiliate customers in the year ended December 31, 2018. See note 16 for more information on revenues from affiliates.

Natural Gas and Natural Gas Liquids Purchases

Cost of natural gas and natural gas liquids represents the cost of our natural gas and natural gas liquids purchased exclusive of depreciation and amortization, Operation and maintenance and General and administrative expenses and consists primarily of product and fuel costs. Estimates for purchases are based on estimated volumes and contracted purchase prices. Estimated purchases are included in Accounts Payable or Accounts Payable-affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Cost of natural gas and natural gas liquids, excluding Depreciation and amortization on the Consolidated Statements of Income.

Operation and Maintenance and General and Administrative Expense

Operation and maintenance expense represents the cost of our service related revenues and consists primarily of labor expenses, lease costs, utility costs, insurance premiums and repairs and maintenance expenses directly related to the operations
10
Exhibit 99.01
of assets. General and administrative expense represents cost incurred to manage the business. This expense includes cost of general corporate services, such as treasury, accounting, legal, information technology and human resources and all other expenses necessary or appropriate to the conduct of business. Any Operation and maintenance expense and General and administrative expense associated with product sales is immaterial.

Environmental Costs

The Partnership expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Partnership expenses amounts that relate to an existing condition caused by past operations that do not have future economic benefit. The Partnership records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. There are $3 million and $0 accrued at December 31, 2020 and 2019, respectively.

Depreciation and Amortization Expense

Depreciation is computed using the straight-line method based on economic lives or a regulatory-mandated recovery period. Amortization of intangible assets is computed using the straight-line method over the respective lives of the intangible assets.

The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets at the time the assets are placed in service. As circumstances warrant, useful lives are adjusted when changes in planned use, changes in estimated production lives of affiliated natural gas basins or other factors indicate that a different life would be more appropriate. Such changes could materially impact future depreciation expense. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. The computation of amortization expense on intangible assets requires judgment regarding the amortization method used. Intangible assets are amortized on a straight-line basis over their useful lives using a method of amortization that reflects the pattern in which the economic benefits of the intangible asset are consumed.

Income Tax

The Partnership’s earnings are not subject to income tax (other than Texas state margin tax and taxes associated with the Partnership’s corporate subsidiary Enable Midstream Services) and are taxable at the individual partner level. For more information, see Note 18.

We account for deferred income tax related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future taxes attributable to the difference between financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of tax net operating loss carryforwards. In the event future utilization is determined to be unlikely, a valuation allowance is provided to reduce the tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the period in which the temporary differences and carryforwards are expected to be recovered or settled. The effect of a change in tax rates is recognized in the period which includes the enactment date. The Partnership recognizes interest and penalties as a component of income tax expense.

Cash and Cash Equivalents

The Partnership considers cash equivalents to be short-term, highly liquid investments with maturities of three months or less from the date of purchase. The Consolidated Balance Sheets have $3 million and $4 million of cash and cash equivalents as of December 31, 2020 and 2019, respectively.

Accounts Receivable and Allowance for Doubtful Accounts

The Partnership adopted ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” on January 1, 2020. Upon adoption, the Partnership recognized a $3 million cumulative adjustment to Partners’ Equity and a corresponding adjustment to Allowance for doubtful accounts.
11
Exhibit 99.01

Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based primarily upon the historical loss-rate method established for various pools of accounts receivables with similar levels of credit risk. The historical loss-rates are then adjusted, as necessary, based on current conditions and forecast information that could result in future uncollectable amounts. On an ongoing basis, we evaluate our customers’ financial strength based on aging of accounts receivable, payment history and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable and other receivable balances within other assets at least quarterly, giving consideration to credit losses, the aging of receivables, specific customer circumstances that may impact their ability to pay the amounts due and current and forecast economic conditions over the assets contractual lives. The following table summarizes the required allowance for doubtful accounts.
December 31, 2020 January 1, 2020
(In millions)
Accounts receivable $ 1  $ 2 
Other assets 3  3 
Total Allowance for doubtful accounts $ 4  $ 5 

Inventory

Materials and supplies inventory is valued at cost and is subsequently recorded at the lower of cost or net realizable value. The Partnership recorded no write-downs to net realizable value related to materials and supplies inventory disposed or identified as excess or obsolete for each of the years ended December 31, 2020, 2019 and 2018. Materials and supplies are recorded to inventory when purchased and, as appropriate, subsequently charged to operation and maintenance expense on the Consolidated Statements of Income or capitalized to property, plant and equipment on the Consolidated Balance Sheets when installed.

Natural gas inventory is held, through the transportation and storage reportable segment, to provide operational support for the intrastate pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the gathering and processing reportable segment, due to timing differences between the production of certain natural gas liquids and ultimate sale to third parties. Natural gas and natural gas liquids inventory is valued using moving average cost and is subsequently recorded at the lower of cost or net realizable value. During the years ended December 31, 2020, 2019 and 2018, the Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of $10 million, $8 million and $4 million, respectively. The cost of gas associated with sales of natural gas and natural gas liquids inventory is presented in Cost of natural gas and natural gas liquids, excluding depreciation and amortization on the Consolidated Statements of Income.
December 31,
2020 2019
(In millions)
Materials and supplies $ 32  $ 32 
Natural gas and natural gas liquids 10  14 
Total Inventory $ 42  $ 46 

Gas Imbalances

Gas imbalances occur when the actual amounts of natural gas delivered from or received by the Partnership’s pipeline systems differ from the amounts scheduled to be delivered or received. Imbalances are due to or due from shippers and operators and can be settled in cash or natural gas depending on contractual terms. The Partnership values all imbalances at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value.

Long-Lived Assets (including Intangible Assets)

The Partnership records property, plant and equipment and intangible assets at historical cost. Newly constructed plant is
12
Exhibit 99.01
added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and capitalized interest. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and charged to Accumulated depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Operation and maintenance expense. The Partnership expenses repair and maintenance costs as incurred. Repair, removal and maintenance costs are included in the Consolidated Statements of Income as Operation and maintenance expense.

Impairment of Long-Lived Assets (including Intangible Assets)

The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. For more information, see Note 8.

Impairment of Investment in Equity Method Affiliate

The Partnership evaluates its Investment in equity method affiliate for impairment when factors indicate that an other than temporary decrease in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. The Partnership utilizes the market or income approaches to estimate the fair value of the investment, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. The resulting fair value of the investment is then compared to the carrying amount of the investment and an impairment charge equal to the difference, is recorded to Equity in earnings (losses) of equity method affiliate, net. Any basis difference between our recognized Investment in equity method affiliate and the underlying financial statements of the affiliate are assigned to the applicable net assets of the affiliate. For more information, see Note 11.

Impairment of Goodwill

The Partnership assesses its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. The Partnership utilizes the market or income approaches to estimate the fair value of the reporting unit, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. The resulting fair value of the reporting unit is then compared to the carrying amount of the reporting unit and an impairment charge is recorded to goodwill for the difference. The Partnership performs its goodwill impairment testing at the reporting unit, which is one level below the transportation and storage and gathering and processing reportable segment level. For more information, see Note 10.

Regulatory Assets and Liabilities

The Partnership applies the guidance for accounting for regulated operations to portions of the transportation and storage reportable segment. The Partnership’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of each of December 31, 2020 and 2019, these removal costs of $25 million and $24 million, respectively, are classified as Regulatory liabilities in the Consolidated Balance Sheets.

Capitalization of Interest and Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates for entities that apply guidance for accounting for regulated operations. Capitalized interest represents the approximate net composite interest cost of borrowed funds used for construction. Interest and AFUDC are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. For the years ended December 31, 2020, 2019 and 2018, the Partnership capitalized interest and
13
Exhibit 99.01
AFUDC of $2 million, $2 million and $6 million, respectively.

Derivative Instruments

The Partnership is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. At times, the Partnership utilizes commodity derivative instruments such as physical forward contracts, financial futures and swaps to mitigate the impact of changes in commodity prices on its operating results and cash flows. Such derivatives are recognized in the Partnership’s Consolidated Balance Sheets at their fair value unless the Partnership elects hedge accounting or the normal purchase and sales exemption for qualified physical transactions. For commodity derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized in Product sales in the Consolidated Statements of Income. A commodity derivative may be designated as a normal purchase or normal sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business.

At times, the Partnership utilizes interest rate derivative instruments such as swaps to mitigate the impact of changes in interest rates on its operating results and cash flows. Such derivatives are recognized in the Partnership’s Consolidated Balance Sheets at their fair value. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period in which the hedged transaction is recognized in earnings.

The Partnership’s policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.

Fair Value Measurements

The Partnership determines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, the Partnership utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy included in current accounting guidance. The Partnership generally applies the market approach to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

Equity-Based Compensation

The Partnership awards equity-based compensation to officers, directors and certain employees under the Long-Term Incentive Plan. All equity-based awards to officers, directors and employees under the Long-Term Incentive Plan, including grants of performance units, time-based phantom units (phantom units) and time-based restricted units (restricted units) are recognized in the Consolidated Statements of Income based on their fair values. The fair value of the phantom units and restricted units are based on the closing market price of the Partnership’s common unit on the grant date. The fair value of the performance units is estimated on the grant date using a lattice-based valuation model that factors in information, including the expected distribution yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the phantom unit and restricted unit awards is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a vesting period. The vesting of the performance unit awards is also contingent upon the probable outcome of the market condition. Depending on forfeitures and actual vesting, the compensation expense recognized related to the awards could increase or decrease.

Employee Benefit Plans

The Partnership has adopted the 401(k) Savings Plan, covering all full-time employees. Participant contributions are discretionary, and can be up to 70% of compensation, as pre-tax, Roth, and /or after-tax contributions, subject to certain limits. We match 100% of employee contributions up to 6% of each participant’s eligible annual compensation, subject to certain limits. Matching contributions provided by the Partnership are immediately vested. The Partnership may also make discretionary profit sharing contributions. Allocations of such profit sharing contributions are based on the proportion of each participant’s eligible compensation of the plan year to the total of all participants’ eligible compensation, as defined. A participant must be employed on the last day of the Plan year in order to receive an allocation of profit sharing contributions.
14
Exhibit 99.01
Profit sharing contributions must be approved by the Board of Directors annually. For the years ended December 31, 2020, 2019 and 2018, the Partnership contributed $20 million, $20 million and $19 million, respectively.

During the years ended December 31, 2020, 2019 and 2018, the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. For the years ended December 31, 2020, 2019 and 2018, the Partnership reimbursed OGE Energy $2 million, $3 million and $3 million, respectively, for these benefits. See Note 16 for further information related to our related party transactions.


(2) New Accounting Pronouncements

Reference Rate Reform

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This standard provides optional guidance, for a limited time, to ease the potential burden in accounting for or recognizing the effects of reference rate reform on financial reporting. The standard was effective upon issuance and generally can be applied through December 31, 2022. The Partnership adopted ASU 2020-04 during the year ended December 31, 2020. The implementation had no material impact on the Consolidated Financial Statements and related disclosures.

In January 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This standard clarifies that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition. ASU 2021-01 also amends the expedients and exceptions in ASC 848 to capture the incremental consequences of the scope clarification and to tailor the existing guidance to derivative instruments affected by the discounting transition. ASU 2021-01 was effective upon issuance and generally can be applied through December 31, 2022. The Partnership expects to adopt this standard in the first quarter of 2021 and does not expect the adoption of this standard to have a material impact on the Consolidated Financial Statements and related disclosures.


(3) Revenues

The following tables disaggregate total revenues by major source from contracts with customers and the gain on derivative activity for the years ended December 31, 2020, 2019 and 2018.
Year Ended December 31, 2020
Gathering and
Processing 		Transportation
and Storage 		Eliminations Total
(In millions)
Revenues:
Product sales:
Natural gas
$ 249  $ 328  $ (285) $ 292 
Natural gas liquids
762  10  (10) 762 
Condensate
68  —  —  68 
Total revenues from natural gas, natural gas liquids, and condensate
1,079  338  (295) 1,122 
Gain on derivative activity
8  2  —  10 
Total Product sales $ 1,087  $ 340  $ (295) $ 1,132 
Service revenues:
Demand revenues
$ 135  $ 491  $ —  $ 626 
Volume-dependent revenues
664  50  (9) 705 
Total Service revenues $ 799  $ 541  $ (9) $ 1,331 
Total Revenues $ 1,886  $ 881  $ (304) $ 2,463 
15
Exhibit 99.01
Year Ended December 31, 2019
Gathering and
Processing 		Transportation
and Storage 		Eliminations Total
(In millions)
Revenues:
Product sales:
Natural gas
$ 368  $ 464  $ (384) $ 448 
Natural gas liquids
943  19  (19) 943 
Condensate
126  —  —  126 
Total revenues from natural gas, natural gas liquids, and condensate
1,437  483  (403) 1,517 
Gain on derivative activity
12  4  —  16 
Total Product sales $ 1,449  $ 487  $ (403) $ 1,533 
Service revenues:
Demand revenues
$ 274  $ 489  $ —  $ 763 
Volume-dependent revenues
615  62  (13) 664 
Total Service revenues $ 889  $ 551  $ (13) $ 1,427 
Total Revenues $ 2,338  $ 1,038  $ (416) $ 2,960 

Year Ended December 31, 2018
Gathering and
Processing 		Transportation
and Storage 		Eliminations Total
(In millions)
Revenues:
Product sales:
Natural gas
$ 480  $ 590  $ (506) $ 564 
Natural gas liquids
1,405  30  (30) 1,405 
Condensate
126  —  —  126 
Total revenues from natural gas, natural gas liquids, and condensate
2,011  620  (536) 2,095 
Gain on derivative activity
5  5  1  11 
Total Product sales $ 2,016  $ 625  $ (535) $ 2,106 
Service revenues:
Demand revenues
$ 252  $ 472  $ —  $ 724 
Volume-dependent revenues
550  65  (14) 601 
Total Service revenues $ 802  $ 537  $ (14) $ 1,325 
Total Revenues $ 2,818  $ 1,162  $ (549) $ 3,431 
Product Sales

Natural Gas, NGLs or Condensate

We deliver natural gas, NGLs and condensate to purchasers at contractually agreed-upon delivery points at which the purchaser takes custody, title, and risk of loss of the commodity. We recognize revenue at the point in time when control transfers to the purchaser at the delivery point based on the contractually agreed upon fixed or index-based price received.

Gain (Loss) on Derivative Activity

Included in Product sales are gains and losses on natural gas, natural gas liquids, and crude oil (for condensate) derivatives that are accounted for under guidance in ASC 815. See Note 13 for further discussion of our derivative and hedging activity.

16
Exhibit 99.01
Service Revenues

Service revenues include demand revenues and volume-dependent revenues, both of which include contracts with customers that typically contain a series of distinct services performed on discrete volumes. For these types of contracts with customers, we typically have a right to consideration from our customers in an amount that corresponds directly with the value to the customer of our performance completed to date and recognize service revenues in accordance with our election to use the right to invoice practical expedient.

Demand revenues

Our demand revenue arrangements are generally structured in one of the following ways:
•Under a firm arrangement, a customer agrees to pay a fixed fee for a contractually agreed upon pipeline or storage capacity, which results in performance obligations for each individual period of reservation. Once the services have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized.
•Under a minimum volume commitment arrangement, a customer agrees to pay the contractually agreed upon gathering, compressing and treating fees for a minimum volume of natural gas or crude oil irrespective of whether or not the minimum volume of natural gas or crude oil is delivered, which results in performance obligations for each individual unit of volume. If the actual volumes exceed the minimum volume of natural gas or crude oil, the customer pays the contractually agreed upon gathering, compressing and treating fees for the excess volumes in addition to the fees paid for the minimum volume of natural gas or crude oil. Once the services have been completed, or the customer no longer has the ability to utilize the services, the performance obligation is met, and revenue is recognized. In addition, when certain minimum volume commitment fee arrangements include commitments of one year or more, significant judgment is used in interim commitment periods in which a customer’s actual volumes are deficient in relation to the minimum volume commitment. Revenue is recognized in proportion to the pattern of past performance exercised by the customer or when the likelihood of the customer meeting the minimum volume commitment becomes remote.

Volume-dependent revenues

Our volume-dependent revenues primarily consist of gathering, compressing, treating, processing, transportation or storage services fees on contracts that exceed their contractually committed volume or do not have firm arrangements or minimum volume commitment arrangements. These revenues are generally variable because the volumes are dependent on throughput by third-party customers for which the service provided is only specified on a daily or monthly basis. Our other fee revenue arrangements typically recognize revenue as the service is performed and have pricing terms that are generally structured in one of the following ways: (1) Contractually agreed upon monetary fee for service or (2) contractually agreed upon consideration received in the form of natural gas or natural gas liquids, which are valued at the current month index-based price, which approximates fair value.

MRT Rate Case Settlements

In June 2018, MRT filed a general NGA rate case (the 2018 Rate Case), and in October 2019, MRT filed a second rate case (the 2019 Rate Case). MRT began collecting the rates proposed in the 2018 Rate Case, subject to refund, on January 1, 2019. On March 26, 2020, FERC issued an order approving settlements filed in the 2018 Rate Case and the 2019 Rate Case. Upon issuance of the order and approval of the settlement of the MRT rate cases, the Partnership recognized $17 million of revenues from amounts previously held in reserve related to transportation and storage services performed in 2019. In May 2020, $21 million previously held in reserve was refunded to customers, which is inclusive of interest.

Accounts Receivable

Payments for all types of revenues are typically received within 30 days of invoice. Invoices for all revenue types are sent on at least a monthly basis, except for the shortfall provisions under certain minimum volume commitment arrangements, which are typically invoiced annually. Accounts receivable includes accrued revenues associated with certain minimum volume commitments that will be invoiced at the conclusion of the measurement period specified under the respective contracts.

17
Exhibit 99.01
The following table summarizes the components of accounts receivable, net of allowance for doubtful accounts.
December 31, 2020 December 31, 2019
(In millions)
Accounts Receivable:
Customers $ 245  $ 239 
Contract assets (1)
12  18 
Non-customers 6  12 
Total Accounts Receivable (2)
$ 263  $ 269 
____________________
(1)Contract assets reflected in Total Accounts Receivable include accrued minimum volume commitments. Contract assets are primarily attributable to revenues associated with estimated shortfall volumes on certain annual minimum volume commitment arrangements. Total Accounts Receivable does not include contract assets related to firm transportation contracts with tiered rates of $9 million as of December 31, 2020 and $6 million as of December 31, 2019, which are reflected in Other Assets.
(2)Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies.

Contract Liabilities

Our contract liabilities primarily consist of the following prepayments received from customers for which the good or service has not yet been provided in connection with the prepayment:
•Under certain firm arrangements, customers pay their demand fee prior to the month of contracted capacity. These fees are applied to the subsequent month’s activity and are included in other current liabilities on the Consolidated Balance Sheets.
•Under certain demand and volume dependent arrangements, customers make contributions of aid in construction payments. For payments that are related to contracts under ASC 606, the payment is deferred and amortized over the life of the associated contract and the unamortized balance is included in other current or long-term liabilities on the Consolidated Balance Sheets.
The table below summarizes the change in the contract liabilities for the year ended December 31, 2020:
Year Ended December 31,
2020 2019
(In millions)
Deferred revenues, beginning of period (1)
$ 48  $ 48 
Amounts recognized in revenues related to the beginning balance (25) (24)
Net additions 21  24 
Deferred revenues, end of period (1)
$ 44  $ 48 

The table below summarizes the timing of recognition of these contract liabilities as of December 31, 2020:
2021 2022 2023 2024 2025 and After
(In millions)
Deferred revenues (1)
$ 23  $ 7  $ 6  $ 6  $ 2 
____________________
(1)Deferred revenues includes deferred revenue—affiliated companies. This amount is included in Other current liabilities and Other long-term liabilities.

18
Exhibit 99.01
Remaining Performance Obligations

We apply certain practical expedients as permitted by ASC 606, in which we are not required to disclose information regarding remaining performance obligations associated with agreements with original expected durations of one year or less, agreements in which we have elected to recognize revenue in the amount to which we have the right to invoice, and agreements where the variable consideration is allocated entirely to wholly unsatisfied performance obligations that generally do not get resolved until actual volumes are delivered and the prices are known. However, certain agreements do not qualify for practical expedients, which consist primarily of firm arrangements and minimum volume commitment arrangements. Upon completion of the performance obligations associated with these arrangements, revenue is recognized as Service revenues in the Consolidated Statements of Income.

The table below summarizes the timing of recognition of the remaining performance obligations as of December 31, 2020.
2021 2022 2023 2024 2025 and After
(In millions)
Transportation and Storage $ 443  $ 371  $ 336  $ 250  $ 938 
Gathering and Processing 120  123  121  101  213 
Total remaining performance obligations $ 563  $ 494  $ 457  $ 351  $ 1,151 


(4) Leases

On January 1, 2019, the Partnership adopted ASU 2016-02, “Leases (ASC 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Partnership has applied the standard only to contracts that were not expired as of January 1, 2019.

The Partnership elected the optional transition practical expedient to not evaluate land easements that exist or expire before the Partnership’s adoption of ASC 842 and that were not previously accounted for as leases under ASC 840. The Partnership elected the optional transition practical expedient to not reassess whether any expired or existing contracts are or contain leases, the lease classification for any expired or existing leases and initial direct costs for any existing leases. Upon adoption, we increased our asset and liability balances on the Consolidated Balance Sheets by approximately $35 million due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that were classified as operating leases. The Partnership did not recognize a material cumulative adjustment to the Consolidated Statements of Partners’ Equity and we did not have any material changes in the timing of expense recognition or our accounting policies.

Description of Lease Contracts

Our lease obligations are primarily comprised of rentals of field equipment and office space, which are recorded as Operation and maintenance and General and administrative expenses in the Partnership’s Consolidated Statements of Income. Other than the contractual terms for each lease obligation, the key inputs for our calculations of the initial right-of-use assets and corresponding lease liabilities are the expected remaining life and applicable discount rate. The Partnership is generally not aware of the implicit rate for either field equipment or office space rental arrangements, so discount rates are based upon the expected term of each arrangement and the Partnership’s uncollateralized borrowing rate associated with the expected term at the time of lease inception. As of December 31, 2020, the weighted average remaining lease term is 7.0 years and the weighted average discount rate is 5.47%. A description of our lease contracts follows:

Field equipment: Field equipment has an expected lease term of 3 to 5 years, with contractual base terms of 1 to 3 years followed by month-to-month renewals. Field equipment rental arrangements do not generally contain any significant variable lease payments. While certain arrangements may include lower standby rates, field equipment is generally anticipated to be in use for all of its expected lease term. The Partnership has compression service agreements, some of which are on a month-to-month basis and some of which expire in 2021. The Partnership also has gas treating lease agreements, of which some are on a month-to-month basis, while others will expire in 2021 and in 2022. Field equipment lease costs are reflected in Operation and maintenance expense in the Consolidated Statements of Income.
19
Exhibit 99.01

Office space: Office spaces have an expected lease term of 7 to 10 years, which is currently the same as the contractual base term. Office space rental arrangements contain market-based renewal options of up to 15 years. Variable lease payments for office spaces are generally comprised of costs for utilities, maintenance and building management services. Variable lease payments due under office space rental arrangements began July 1, 2019, with amounts due monthly. The Partnership occupies principal executive offices in Oklahoma City, Oklahoma, as well as office space in Houston, Texas. Our office leases are long-term in nature and represent $17 million of our right-of-use assets and $20 million of our lease liability as of December 31, 2020. Office space lease costs, including a proportionate percentage of facility expenses, are reflected in General and administrative expense in the Consolidated Statements of Income.

The table below summarizes the operating leases included in the Consolidated Balance Sheets.

Balance Sheet Location December 31, 2020 December 31, 2019
    (In millions)
Operating lease asset Other Assets $ 25  $ 37 
Total right-of-use assets $ 25  $ 37 
Operating lease liabilities Other Current Liabilities $ 4  $ 9 
Operating lease liabilities Other Liabilities 24  31 
Total lease liabilities $ 28  $ 40 

As of December 31, 2020, all lease obligations were classified as operating leases. Therefore, all cash flows are reflected in Cash Flows from Operating Activities.

The following table presents the Partnership’s rental costs associated with field equipment and office space.

Year Ended December 31,
2020 2019
(In millions)
Rental Costs:
Field equipment
$ 16  $ 29 
Office space
6  7 

The following table presents the Partnership’s lease cost.
Year Ended December 31,
2020 2019
(In millions)
Lease Cost:
Operating lease cost $ 8  $ 11 
Short-term lease cost 12  24 
Variable lease cost 2  1 
Total Lease Cost $ 22  $ 36 

The Partnership recorded short-term lease costs of $1 million and $2 million in the transportation and storage reportable segment during the years ended December 31, 2020 and 2019, respectively. All other lease costs were included in the gathering and processing reportable segment.
20
Exhibit 99.01

Under ASC 842, as of December 31, 2020, the Partnership has operating lease obligations expiring at various dates. Undiscounted cash flows for operating lease liabilities are as follows:
Non-cancellable operating leases
(In millions)
Year Ending December 31,
2021 $ 6 
2022 5 
2023 5 
2024 4 
2025 3 
After 2025 8 
Total 31 
Less: impact of the applicable discount rate 3 
Total lease liabilities $ 28 

ASC 840 Lease Accounting

Under ASC 840 rental expense was $35 million during the year ended December 31, 2018.


(5) Acquisition

EOCS Acquisition

On November 1, 2018, the Partnership acquired all of the equity interests in Velocity Holdings, LLC, now EOCS, which owns and operates a crude oil and condensate gathering system in the SCOOP and STACK plays of the Anadarko Basin, for approximately $444 million in cash. The acquisition was accounted for as a business combination and was funded with borrowings under the commercial paper program. During the fourth quarter of 2018, the Partnership finalized the purchase price allocation as of November 1, 2018.

The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date:
Purchase price allocation (in millions):
Assets acquired:
Cash $ 1 
Current Assets 3 
Property, plant and equipment 124 
Intangibles 259 
Goodwill 86 
Liabilities assumed:
Current liabilities 1 
Less: Noncontrolling interest at fair value 28 
Total identifiable net assets $ 444 

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 15 years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Anadarko Basin and is allocated to the gathering and processing reportable segment. Included within the acquisition was 60% of a 26-mile pipeline system joint venture with a third party which owns and operates a refinery connected to the EOCS system. This joint venture’s financials have been consolidated within the accompanying Consolidated Financial Statements. The Partnership incurred approximately $6 million of acquisition costs associated with this transaction during the year ended December 31, 2018, which were included in General and
21
Exhibit 99.01
administrative expense in the Consolidated Statements of Income. The Partnership determined not to include pro forma Consolidated Financial Statements for the year ended December 31, 2018, as the impact would not be material.


(6) Earnings Per Limited Partner Unit

Basic and diluted earnings per limited partner unit is calculated by dividing net income allocable to common and subordinated units by the weighted average number of common and subordinated units outstanding during the period. Any common units issued during the period are included on a weighted average basis for the days in which they were outstanding.

The following table illustrates the Partnership’s calculation of earnings per unit for common units:
Year Ended December 31,
2020 2019 2018
(In millions, except per unit data)
Net income $ 83  $ 400  $ 523 
Net income (loss) attributable to noncontrolling interests (5) 4  2 
Series A Preferred Unit distributions 36  36  36 
General partner interest in net income —  —  — 
Net income available to common units $ 52  $ 360  $ 485 
Net income allocable to common units $ 52  $ 360  $ 485 
Dilutive effect of Series A Preferred Unit distribution (1)
—  —  — 
Diluted net income allocable to common units
$ 52  $ 360  485 
Basic weighted average number of outstanding common units (2)
437  436  434 
Dilutive effect of Series A Preferred Units (1)
—  —  — 
Dilutive effect of performance units (3)
1  1  2 
Diluted weighted average number of outstanding common units 438  437  436 
Basic and diluted earnings per common unit
Basic $ 0.12  $ 0.83  $ 1.12 
Diluted $ 0.12  $ 0.82  $ 1.11 
____________________
(1)For the years ended December 31, 2020, 2019, and 2018, the issuance of “if-converted” common units attributable to the Series A Preferred Units were excluded in the calculation of diluted earnings per common unit as the impact was anti-dilutive.
(2)Basic weighted average number of outstanding common units for the years ended December 31, 2020, 2019, and 2018 includes approximately 2 million, 1 million, and 1 million time-based phantom units, respectively.
(3)The dilutive effect of the performance unit awards was less than $0.01 per unit for the years ended December 31, 2020, 2019, and 2018.


(7) Partners’ Equity

The Partnership Agreement requires that, within 60 days after the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) to unitholders of record on the applicable record date.

22
Exhibit 99.01
The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders, as applicable, during 2020, 2019 and 2018 (in millions, except for per unit amounts):
Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution
2020
December 31, 2020 (1)
February 22, 2021 March 1, 2021 $ 0.16525  $ 72 
September 30, 2020 November 17, 2020 November 24, 2020 0.16525  72 
June 30, 2020 August 18, 2020 August 25, 2020 0.16525  72 
March 31, 2020 May 19, 2020 May 27, 2020 0.16525  72 
2019
December 31, 2019 February 18, 2020 February 25, 2020 $ 0.3305  $ 144 
September 30, 2019 November 19, 2019 November 26, 2019 0.3305  144 
June 30, 2019 August 20, 2019 August 27, 2019 0.3305  144 
March 31, 2019 May 21, 2019 May 29, 2019 0.318  138 
2018
December 31, 2018 February 19, 2019 February 26, 2019 $ 0.318  $ 138 
September 30, 2018 November 16, 2018 November 29, 2018 0.318  138 
June 30, 2018 August 21, 2018 August 28, 2018 0.318  138 
March 31, 2018 May 22, 2018 May 29, 2018 0.318  138 
_____________________
(1)The Board of Directors declared a $0.16525 per common unit cash distribution on February 12, 2021, to be paid on March 1, 2021, to common unitholders of record at the close of business on February 22, 2021.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2020, 2019, and 2018 (in millions, except for per unit amounts):
Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution
2020
December 31, 2020 (1)
February 12, 2021 February 12, 2021 $ 0.625  $ 9 
September 30, 2020 November 3, 2020 November 13, 2020 0.625 9
June 30, 2020 August 4, 2020 August 14, 2020 0.625 9
March 31, 2020 May 5, 2020 May 15, 2020 0.625 9
2019
December 31, 2019 February 7, 2020 February 14, 2020 $ 0.625  $ 9 
September 30, 2019 November 5, 2019 November 14, 2019 0.625 9 
June 30, 2019 August 2, 2019 August 14, 2019 0.625 9 
March 31, 2019 April 29, 2019 May 15, 2019 0.625 9 
2018
December 31, 2018 February 8, 2019 February 14, 2019 $ 0.625  $ 9 
September 30, 2018 November 6, 2018 November 14, 2018 0.625 9 
June 30, 2018 August 1, 2018 August 14, 2018 0.625 9 
March 31, 2018 May 1, 2018 May 15, 2018 0.625 9 
_____________________
(1)The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on February 12, 2021, to be paid on February 12, 2021 to Series A Preferred unitholders of record at the close of business on February 12, 2021.

23
Exhibit 99.01
General Partner Interest and Incentive Distribution Rights

Enable GP owns a non-economic general partner interest in the Partnership and, except as provided below with respect to incentive distribution rights, will not be entitled to distributions that the Partnership makes prior to the liquidation of the Partnership in respect of such general partner interest. Enable GP currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from operating surplus (as defined in the Partnership Agreement) in excess of $0.330625 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Enable GP or its affiliates may receive on common units that they own.

Series A Preferred Units

The Partnership has 14,520,000 Series A Preferred Units, representing limited partner interests in the Partnership, which were issued at a price of $25.00 per Series A Preferred Unit on February 18, 2016.

Pursuant to the Partnership Agreement, the Series A Preferred Units:
•rank senior to the Partnership’s common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up;
•have no stated maturity;
•are not subject to any sinking fund; and
•will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change of control.

Holders of the Series A Preferred Units receive a quarterly cash distribution on a non-cumulative basis if and when declared by the General Partner, and subject to certain adjustments, equal to an annual rate of: 10% on the stated liquidation preference of $25.00 from the date of original issue to, but not including, the five year anniversary of the original issue date; and thereafter a percentage of the stated liquidation preference equal to the sum of the three-month LIBOR plus 8.5%.

At any time on or after February 18, 2021, the Partnership may redeem the Series A Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.50 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. Following changes of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units. If, upon a change of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) does not exercise this option, then the holders of the Series A Preferred Units have the option to convert the Series A Preferred Units into a number of common units per Series A Preferred Unit as set forth in the Partnership Agreement. If under certain circumstances the Series A Preferred Units are not eligible for trading on the New York Stock Exchange, the Series A Preferred Units are required to be redeemed by the Partnership.

In addition, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units at any time following a reduction by any of the ratings agencies in the amount of equity content attributed to the Series A Preferred Units. On July 30, 2019, S&P announced that it was reclassifying the Series A Preferred Units from having 50% equity content to having minimal equity content. S&P’s announcement followed a revision of its criteria for evaluating the amount of equity credit attributable to hybrid securities. As a result the reduction of equity content attributed to the Series A Preferred Units by S&P, the Partnership may redeem the Series A Preferred Units at any time, upon not less than 30 days’ nor more than 60 days’ notice, at a price of $25.50 per Series A Preferred Unit plus an amount equal to all unpaid distributions thereon from the issuance date through the redemption date.

Holders of Series A Preferred Units have no voting rights except for limited voting rights with respect to potential amendments to the Partnership Agreement that have a material adverse effect on the existing terms of the Series A Preferred Units, the issuance by the Partnership of certain securities, approval of certain fundamental transactions and as required by law.

Upon the transfer of any Series A Preferred Unit to a non-affiliate of CenterPoint Energy, the Series A Preferred Units will automatically convert into a new series of preferred units (the Series B Preferred Units) on the later of the date of transfer and the second anniversary of the date of issue. The Series B Preferred Units will have the same terms as the Series A Preferred Units except that unpaid distributions on the Series B Preferred Units will accrue on a cumulative basis until paid.

At the closing of the private placement of Series A Preferred Units, the Partnership entered into a registration rights agreement with CenterPoint Energy, pursuant to which, among other things, CenterPoint Energy has certain rights to require the Partnership to file and maintain a registration statement with respect to the resale of the Series A Preferred Units and any other
24
Exhibit 99.01
series of preferred units or common units representing limited partner interests in the Partnership that are issuable upon conversion of the Series A Preferred Units.

ATM Program

On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement in connection with an ATM Program. Pursuant to the ATM Program, the Partnership may issue and sell common units having an aggregate offering price of up to $200 million, by sales methods and at prices determined by market conditions and other factors at the time of our offerings. For the year ended December 31, 2020, the Partnership did not sell any common units under the ATM Program. For the year ended December 31, 2019, the Partnership sold an aggregate of 140,920 common units under the ATM Program, which generated proceeds of approximately $2 million (net of approximately $25,000 of commissions). The registration statement filed with the SEC for the ATM Program expired on May 12, 2020, and the Partnership did not file a replacement registration statement.


(8) Property, Plant and Equipment

Property, plant and equipment includes the following:
Weighted Average Useful Lives
(Years) 		December 31,
2020 2019
(In millions)
Property, plant and equipment, gross:
Gathering and Processing
34.5 $ 8,275  $ 8,252 
Transportation and Storage
40.6 4,802  4,778 
Construction work-in-progress
143  131 
Total $ 13,220  $ 13,161 
Accumulated depreciation:
Gathering and Processing
1,429  1,252 
Transportation and Storage 1,126  1,039 
Total accumulated depreciation 2,555  2,291 
Property, plant and equipment, net
$ 10,665  $ 10,870 

The Partnership recorded depreciation expense of $358 million, $371 million and $351 million during the years ended December 31, 2020, 2019 and 2018, respectively. Effective January 1, 2019, the Partnership completed a depreciation study for the Gathering and Processing and Transportation and Storage reportable segments and the new depreciation rates were applied prospectively as a change in accounting estimate. On March 26, 2020, FERC issued an order approving MRT’s 2018 Rate Case and 2019 Rate Case settlements. As a result of the settlements, the new depreciation rates for MRT have been applied in accordance with the order. The new depreciation rates did not result in a material change in depreciation expense or results of operations.

Impairment of Property, Plant and Equipment

The Partnership periodically evaluates property, plant and equipment for impairment when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. Due to decreases in natural gas and NGL market prices during 2020 as a result of the ongoing COVID-19 pandemic and the economic effects of the pandemic, together with the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, as of March 31, 2020, management reassessed the carrying value of the Atoka assets, in which the Partnership owns a 50% interest in the consolidated joint venture, which is a component of the gathering and processing segment. Based on forecasted future undiscounted cash flows, management determined that the carrying value of the Atoka assets were not fully recoverable. The Partnership utilized the income approach (generally accepted valuation approach) to estimate the fair value of these assets. The primary inputs are forecasted cash flows and the discount rate. The fair value measurement is based on inputs that are not observable in the market and thus represent Level 3 inputs. Applying a discounted cash flow model to the property, plant and equipment, the Partnership recognized a $16 million
25
Exhibit 99.01
impairment, which is included in Impairments of property, plant and equipment and goodwill on the Consolidated Statements of Income during the year ended December 31, 2020.

Sale and Retirements of Assets

The Partnership recognizes gains or losses on sale or retirement when the net book value differs from the consideration received from sales proceeds, insurance recovery or other exchanges.

On September 23, 2019, the Partnership entered into an agreement to sell its undivided 1/12th interest in the Bistineau Storage Facility in Louisiana for approximately $19 million. On January 27, 2020, FERC approved the sale. The Partnership closed the sale on April 1, 2020. We did not recognize a gain or loss on this transaction.

In April 2020, we sustained damage to an approximately 100-mile gas gathering system in the Ark-La-Tex Basin of our gathering and processing segment. We have ceased operation of this system and are in the process of retiring it. We recognized a loss on retirement of approximately $20 million for the year ended December 31, 2020, which is included in Operation and maintenance expense in the Consolidated Statements of Income.

Additionally, for the years ended December 31, 2020, 2019 and 2018, the Partnership recognized other net losses on sale or retirement of approximately $4 million, $8 million and $1 million, respectively, which are included in Operation and maintenance expense in the Consolidated Statements of Income.


(9) Intangible Assets, Net

The Partnership has intangible assets associated with customer relationships related to the acquisitions of Enogex LLC, Monarch Natural Gas, LLC, ETGP and EOCS as follows:
December 31,
2020 2019
(In millions)
Customer relationships:
Total intangible assets $ 840  $ 840 
Accumulated amortization 301  239 
Net intangible assets $ 539  $ 601 

Intangible assets related to customer relationships have a weighted average useful life of 14 years. Intangible assets do not have any significant residual value or renewal options of existing terms. There are no intangible assets with indefinite useful lives.

The Partnership recorded amortization expense of $62 million, $62 million and $47 million during the years ended December 31, 2020, 2019 and 2018, respectively. The following table summarizes the Partnership’s expected amortization of intangible assets for each of the next five years:
2021 2022 2023 2024 2025
(In millions)
Expected amortization of intangible assets $ 62  $ 62  $ 62  $ 62  $ 62 


(10) Goodwill

In the fourth quarter of 2017, as a result of the acquisition of ETGP, the Partnership recorded $12 million of goodwill associated with the Ark-La-Tex Basin reporting unit, included in the gathering and processing reportable segment. In the fourth quarter of 2018, as a result of the acquisition of EOCS, the Partnership recorded $86 million of goodwill associated with the Anadarko Basin reporting unit, included in the gathering and processing reportable segment.

The Partnership tests its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by
26
Exhibit 99.01
comparing the fair value of the reporting unit with its book value, including goodwill. During 2020, the commodity price declines due to the existing oversupply of crude oil, NGLs and natural gas were exacerbated by the ongoing COVID-19 pandemic and the economic effects of the pandemic, in addition to the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia in the first quarter. Despite the subsequent agreement in April 2020 by a coalition of nations including Russia and Saudi Arabia to reduce production of crude oil, the price of NGLs and crude oil have remained significantly lower than pre-pandemic levels. Amid such crude oil, NGL and natural gas price declines, producers cut back spending and shifted their focus from emphasizing reserves growth, to increasing net cash flows and reducing outstanding debt, which consequently resulted in a decrease in rig count and in forecasted producer activity in the Ark-La-Tex Basin reporting unit during the first quarter of 2020. At the same time, unit prices and market multiples for midstream companies with gathering and processing operations dropped to their lowest levels in the last three years. Due to the continuing decrease in forward commodity prices, the reduction in forecasted producer activities, the resulting decrease in our forecasted cash flows and the increase in the weighted average cost of capital, the Partnership determined that the fair value of the goodwill associated with our Ark-La-Tex Basin reporting unit was more likely than not impaired as of March 31, 2020. As a result, the Partnership performed a quantitative test for our goodwill and determined that the carrying value of the Ark-La-Tex Basin reporting unit exceeded its fair value and that goodwill associated with the Ark-La-Tex Basin was completely impaired in the amount of $12 million. The impairment is included in Impairments of property plant, and equipment and goodwill on the Consolidated Statements of Income for the year ended December 31, 2020.

During 2019, the crude oil and natural gas industry was impacted by current and forward commodity price declines. Amid such crude oil, natural gas and NGL price declines, producers cut back spending and shifted their focus from emphasizing reserves growth, to increasing net cash flows and reducing outstanding debt, which consequently resulted in a decrease in rig count and in forecasted producer activity in the Anadarko Basin reporting unit during the fourth quarter of 2019. At the same time, unit prices and market multiples for midstream companies with gathering and processing operations have dropped to their lowest levels in the last three years. Due to the continuing decrease in forward commodity prices, the reduction in forecasted producer activities, the resulting decrease in our forecasted cash flows and the increase in the weighted average cost of capital, the Partnership determined that the fair value of the goodwill associated with our Anadarko Basin reporting unit would more likely than not be impaired. As a result, the Partnership performed a quantitative test for our annual goodwill impairment analysis as of October 1, 2019, and determined that the carrying value of the Anadarko Basin reporting unit exceeded its fair value and that goodwill associated with the Anadarko Basin reporting unit was completely impaired in the amount of $86 million. The impairment is included in Impairments on the Consolidated Statements of Income for the year ended December 31, 2019.

The change in carrying amount of goodwill in each of our reportable segments is as follows:
Gathering and Processing Transportation and Storage Total
(in millions)
Balance as of December 31, 2018 $ 98  $ —  $ 98 
Goodwill impairment (86) —  (86)
Balance as of December 31, 2019 12  —  12 
Goodwill impairment (12) —  (12)
Balance as of December 31, 2020 $ —  $ —  $ — 


(11) Investment in Equity Method Affiliate

The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence.

SESH is owned 50% by Enbridge Inc. and 50% by the Partnership for the years ended December 31, 2020 and 2019. Pursuant to the terms of the SESH LLC Agreement, if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its limited partner interest in the Partnership and its economic interest in Enable GP, or does not have the ability to exercise certain control rights, Enbridge Inc. may, under certain circumstances, have the right to purchase the Partnership’s interest in SESH at fair market value, subject to certain exceptions.

At September 30, 2020, the Partnership estimated the fair value of its investment in SESH was below the carrying value and concluded the decline in value was other than temporary due to the expiration of a transportation contract and then current status of renewal negotiations. As a result, the Partnership recorded a $225 million impairment on its investment in SESH,
27
Exhibit 99.01
which is included in Equity in earnings (losses) of equity method affiliate, net in the Partnership’s Consolidated Statements of Income for the year ended December 31, 2020. The impairment analysis of the Partnership’s investment in SESH compared the estimated fair value of the investment to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches. Due to the significant unobservable estimates and assumptions required, the Partnership concluded that the fair value estimate should be classified as a Level 3 measurement within the fair value hierarchy. The basis difference for our investment in SESH has been assigned to its property, plant and equipment and will be amortized over its approximately 50-year remaining useful life. See Note 1 for further information concerning the method used to evaluate and measure the impairment on the Partnership’s investment in SESH.

The Partnership shares operations of SESH with Enbridge Inc. under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. During the years ended December 31, 2020, 2019 and 2018, the Partnership billed SESH $15 million, $17 million and $18 million, respectively, associated with these service agreements.

The Partnership includes equity in earnings (losses) of equity method affiliate, net under the Other Income (Expense) caption in the Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018.

SESH:
Year Ended December 31,
2020 2019 2018
(In millions)
Equity in Earnings of Equity Method Affiliate $ 15  $ 17  $ 26 
Impairment of equity method affiliate investment (225) —  — 
Equity in earnings (losses) of equity method affiliate, net $ (210) $ 17  $ 26 
Distributions from Equity Method Affiliate (1)
$ 23  $ 25  $ 33 
____________________ 
(1)Distributions from equity method affiliate includes a $15 million, $17 million and $26 million return on investment and a $8 million, $8 million and $7 million return of investment for the years ended December 31, 2020, 2019 and 2018, respectively.

Summarized financial information of SESH:
December 31,
  2020 2019
  (In millions)
Balance Sheets:
Current assets $ 49  $ 49 
Property, plant and equipment, net 1,043  1,060 
Total assets $ 1,092  $ 1,109 
Current liabilities $ 31  $ 30 
Long-term debt 398  398 
Members’ equity 663  681 
Total liabilities and members’ equity $ 1,092  $ 1,109 
Reconciliation:
Investment in SESH $ 76  $ 309 
Add: Capitalized interest on investment in SESH (1) (1)
Add: Basis difference, net of amortization (1)
256  33 
The Partnership’s share of members’ equity $ 331  $ 341 
____________________ 
(1)Includes the Partnership’s impairment of investment in equity method affiliate of $225 million recorded during the year ended December 31, 2020.

28
Exhibit 99.01
Year Ended December 31,
2020 2019 2018
(In millions)
Income Statements:
Revenues $ 96  $ 109  $ 112 
Operating income 44  50  67 
Net income 26  33  50 


(12) Debt
 
The following table presents the Partnership’s outstanding debt as of December 31, 2020 and 2019.
December 31, 2020 December 31, 2019
Outstanding Principal
Premium (Discount)(1)
Total Debt Outstanding Principal
Premium (Discount)(1)
Total Debt
(In millions)
Commercial Paper $ 250  $ —  $ 250  $ 155  $ —  $ 155 
Revolving Credit Facility —  —  —  —  —  — 
2019 Term Loan Agreement 800  —  800  800  —  800 
2024 Notes 600  —  600  600  —  600 
2027 Notes 700  (2) 698  700  (2) 698 
2028 Notes 800  (5) 795  800  (5) 795 
2029 Notes 547  (1) 546  550  (1) 549 
2044 Notes 531  —  531  550  —  550 
EOIT Senior Notes —  —  —  250  1  251 
Total debt $ 4,228  $ (8) $ 4,220  $ 4,405  $ (7) $ 4,398 
Less: Short-term debt (2)
250  155 
Less: Current portion of long-term debt (3)
—  251 
Less: Unamortized debt expense (4)
19  23 
Total long-term debt $ 3,951  $ 3,969 
___________________
(1)Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.
(2)Short-term debt includes $250 million and $155 million of commercial paper outstanding as of December 31, 2020 and 2019, respectively.
(3)As of December 31, 2019, Current portion of long-term debt included the $251 million outstanding balance of the EOIT Senior Notes which were repaid in March 2020.
(4)As of December 31, 2020 and 2019, there was an additional $3 million and $4 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above. Unamortized debt expense is amortized over the life of the respective debt.

Maturities of outstanding debt, excluding unamortized premiums (discounts), are as follows (in millions):
2021 $ 250 
2022 800 
2023 — 
2024 600 
2025 — 
Thereafter $ 2,578 

29
Exhibit 99.01
Commercial Paper

The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There were $250 million and $155 million outstanding under our commercial paper program at December 31, 2020 and December 31, 2019, respectively. The weighted average interest rate for the outstanding commercial paper was 0.86% as of December 31, 2020.

Revolving Credit Facility

On April 6, 2018, the Partnership amended and restated its Revolving Credit Facility. As amended and restated, the Revolving Credit Facility is a $1.75 billion, five-year senior unsecured revolving credit facility, which under certain circumstances may be increased from time to time up to an additional $875 million. The Revolving Credit Facility is scheduled to mature on April 6, 2023, subject to an extension option, which could be exercised two times to extend the term of the Revolving Credit facility, in each case, for an additional two-year term. As of December 31, 2020, there were no principal advances and no letters of credit outstanding under the restated Revolving Credit Facility.

The Revolving Credit Facility provides that outstanding borrowings bear interest at LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s designated credit ratings from S&P, Moody’s and Fitch Ratings. As of December 31, 2020, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit ratings. As of December 31, 2020, the commitment fee under the Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s Consolidated Statements of Income.

The Revolving Credit Facility contains a financial covenant requiring us to maintain a ratio of consolidated funded debt to consolidated EBITDA as defined under the Revolving Credit Facility as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for any three fiscal quarters including and following any fiscal quarter in which the aggregate value of one or more acquisitions by us or certain of our subsidiaries with a purchase price of at least $25 million in the aggregate, the consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to 5.50 to 1.00. Additionally, for the period of time during the construction by the Partnership or certain of its subsidiaries of a qualified project with a cost greater than $15 million and before the date such qualified project is substantially complete and commercially operable, the Partnership may make Qualified Project EBITDA Adjustments (as defined in the Revolving Credit Facility and 2019 Term Loan Agreement) by determining an amount as projected consolidated EBITDA attributable to such qualified project, which may be added to the actual consolidated EBITDA for the Partnership and those certain subsidiaries; provided that such amount (i) shall be no greater than 20% of the total actual consolidated EBITDA of the Partnership and those certain subsidiaries (as determined without the projected consolidated EBITDA attributable to such qualified project) and (ii) shall be subject to approval by the administrative agent.

The Revolving Credit Facility also contains covenants that restrict us and certain subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of subsidiary indebtedness, incurrence of liens, transactions with affiliates, designation of subsidiaries as Excluded Subsidiaries (as defined in the Revolving Credit Facility), restricted payments, changes in the nature of their respective businesses and entering into certain restrictive agreements. Borrowings under the Revolving Credit Facility are subject to acceleration upon the occurrence of certain defaults, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100 million or more in the aggregate, change of control, nonpayment of uninsured money judgments in excess of $100 million and the occurrence of certain ERISA and bankruptcy events, subject where applicable to specified cure periods.

2019 Term Loan Agreement

On January 29, 2019, the Partnership entered into an unsecured term loan agreement with Bank of America, N.A., as administrative agent, and the several lenders thereto. As of December 31, 2020, there was $800 million outstanding under the 2019 Term Loan Agreement. The 2019 Term Loan Agreement has a scheduled maturity date of January 29, 2022, but contains an option, which may be exercised up to two times, to extend the maturity date for an additional one-year term, subject to lender approval. The 2019 Term Loan Agreement provides that outstanding borrowings bear interest at the Eurodollar rate and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s credit ratings. The applicable margin shall equal, (1) in the case of interest rates determined by reference to the Eurodollar rate,
30
Exhibit 99.01
between 0.75% and 1.50% per annum and (2) in the case of interest rates determined by reference to the alternate base rate, between 0% and 0.50% per annum. As of December 31, 2020, the applicable margin for LIBOR-based advances under the 2019 Term Loan Facility was 1.25% based on the Partnership’s credit ratings. As of December 31, 2020, the weighted average interest rate of the 2019 Term Loan Agreement was 2.10%.

The 2019 Term Loan Agreement contains a financial covenant requiring the Partnership to maintain a ratio of consolidated funded debt to consolidated EBITDA as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for a certain period time following an acquisition by the Partnership or certain of its subsidiaries with a purchase price that when combined with the aggregate purchase price for all other such acquisitions in any rolling 12-month period, is equal to or greater than $25 million, the consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to 5.50 to 1.00. For further discussion of Qualified Project EBITDA Adjustments, see “Revolving Credit Facility” above.

The 2019 Term Loan Agreement also contains covenants that restrict the Partnership and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of subsidiary indebtedness, incurrence of liens, transactions with affiliates, designation of subsidiaries as Excluded Subsidiaries (as defined in the 2019 Term Loan Agreement), restricted payments, changes in the nature of their respective business and entering into certain restrictive agreements. The 2019 Term Loan Agreement is subject to acceleration upon the occurrence of certain defaults, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100 million or more in the aggregate, change of control, nonpayment of uninsured judgments in excess of $100 million, and the occurrence of certain ERISA and bankruptcy events, subject, where applicable, to specified cure periods.

Senior Notes

As of December 31, 2020, the Partnership’s debt included the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes, which had $8 million of unamortized discount and $19 million of unamortized debt expense at December 31, 2020, resulting in effective interest rates of 4.01%, 4.56%, 5.19%, 4.29% and 4.99%, respectively, during the year ended December 31, 2020. In May 2019, the Partnership’s 2019 Notes matured and were paid using proceeds from the 2019 Term Loan Agreement. In March 2020, the EOIT Senior Notes matured and were paid using proceeds from the Revolving Credit Facility.

During the year ended December 31, 2020, the Partnership repurchased $22 million aggregate principal amount of the 2029 Notes and 2044 Notes in open market transactions for approximately $17 million plus accrued interest, which resulted in a $5 million gain on extinguishment of debt. The gain is included in Other, net in the Consolidated Statements of Income.

The indenture governing the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes contains certain restrictions, including, among others, limitations on our ability and the ability of our principal subsidiaries to: (i) consolidate or merge and sell all or substantially all of our and our subsidiaries’ assets and properties; (ii) create, or permit to be created or to exist, any lien upon any of our or our principal subsidiaries’ principal property, or upon any shares of stock of any principal subsidiary, to secure any debt; and (iii) enter into certain sale-leaseback transactions. These covenants are subject to certain exceptions and qualifications.

As of December 31, 2020, the Partnership was in compliance with all of their debt agreements, including financial covenants.


(13) Derivative Instruments and Hedging Activities

The primary risks managed using derivative instruments are commodity price and interest rate risks. The Partnership is also exposed to credit risk in its business operations.

Commodity Price Risk

The Partnership uses forward physical contracts, commodity price swap contracts and commodity price option features to manage its commodity price risk exposures. Commodity derivative instruments used by the Partnership are as follows:
•NGL options, futures, swaps and swaptions, and WTI crude oil options, futures, swaps and swaptions are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;
31
Exhibit 99.01
•natural gas options, futures, swaps and swaptions and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas price exposure associated with its gathering, processing, transportation and storage assets, contracts and asset management activities.
Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by its gathering and processing business.

The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and are recorded as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value on a net basis with such amounts classified as current or long-term based on their anticipated settlement.

As of December 31, 2020 and 2019, the Partnership had no commodity derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

Interest Rate Risk

The Partnership uses interest rate swap contracts to manage its interest rate risk exposures. The Partnership recognizes its interest rate derivative instruments as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. The Partnership’s interest rate swap contracts are designated as cash flow hedging instruments for accounting purposes. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized currently in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period the hedged transaction affects earnings. As of December 31, 2020 and 2019, the Partnership had no interest rate derivative instruments that were designated as fair value hedges for accounting purposes.

Credit Risk

Credit risk includes the risk that counterparties that owe the Partnership money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Partnership may seek or be forced to enter into alternative arrangements. In that event, the Partnership’s financial results could be adversely affected, and the Partnership could incur losses.

Derivatives Not Designated as Hedging Instruments

Derivative instruments not designated as hedging instruments for accounting purposes are utilized to manage the Partnership’s exposure to commodity price risk. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Quantitative Disclosures Related to Derivative Instruments Not Designated as Hedging Instruments

The majority of natural gas physical purchases and sales not designated as hedges for accounting purposes are priced based on a monthly or daily index, and the fair value is subject to little or no market price risk. Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via the Partnership’s processing contracts, which are not derivative instruments.

32
Exhibit 99.01
As of December 31, 2020 and 2019, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:
 
December 31, 2020 December 31, 2019
  Gross Notional Volume
  Purchases Sales Purchases Sales
Natural gas— TBtu (1)
Financial fixed futures/swaps —  18  10  19 
Financial basis futures/swaps —  27  11  30 
Financial swaptions (2)
—  7  —  2 
Physical purchases/sales —  —  —  6 
Crude oil (for condensate)— MBbl (3)
Financial futures/swaps
—  465  —  990 
Financial swaptions (2)
—  90  —  225 
Natural gas liquids— MBbl (4)
Financial futures/swaps
855  1,210  2,490  2,415 
Financial swaptions (2)
—  45  —  — 
____________________
(1)As of December 31, 2020, 95.7% of the natural gas contracts had durations of one year or less and 4.3% had durations of more than one year and less than two years. As of December 31, 2019, 86.6% of the natural gas contracts had durations of one year or less and 13.4% had durations of more than one year and less than two years.
(2)The notional value contains a combined derivative instrument consisting of a fixed price swap and a sold option, which gives the counterparties the right, but not the obligation, to increase the notional quantity hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.
(3)As of December 31, 2020, 100.0% of the crude oil (for condensate) contracts had durations of one year or less. As of December 31, 2019, 72.8% of the crude oil (for condensate) contracts had durations of one year or less and 27.2% had durations of more than one year and less than two years.
(4)As of December 31, 2020, 100.0% of the natural gas liquids contracts had durations of one year or less. As of December 31, 2019, 72.2% of the natural gas liquids contracts had durations of one year or less and 27.8% had durations of more than one year and less than two years.

Derivatives Designated as Hedging Instruments

Derivative instruments designated as hedging instruments for accounting purposes are utilized in managing the Partnership’s interest rate risk exposures.

Quantitative Disclosures Related to Derivative Instruments Designated as Hedging Instruments

The derivative instruments designated as hedges for accounting purposes are interest rate derivative instruments priced on monthly interest rates.

As of December 31, 2020 and 2019, the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes:
December 31, 2020 December 31, 2019
  
Gross Notional Value
(In millions)
Interest rate swaps $ 300  $ 300 

33
Exhibit 99.01
Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets at December 31, 2020 and 2019 that were not designated as hedging instruments for accounting purposes are as follows:
 
December 31, 2020 December 31, 2019
    Fair Value
Instrument Balance Sheet Location Assets Liabilities Assets Liabilities
    (In millions)
Natural gas
Financial futures/swaps Other Current $ 2  $ 2  $ 7  $ 5 
Financial swaptions Other Current 1  2  —  — 
Physical purchases/sales Other Current —  —  5  — 
Financial futures/swaps Other —  —  —  1 
Crude oil (for condensate)
Financial futures/swaps Other Current 1  13  1  19 
Financial futures/swaps Other —  —  —  8 
Natural gas liquids
Financial futures/swaps Other Current 15  3  25  3 
Financial swaptions Other Current —  1  —  — 
Financial futures/swaps Other —  —  11  2 
Total gross derivatives (1)
$ 19  $ 21  $ 49  $ 38 
_____________________
(1)See Note 14 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2020 and 2019.

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets as of December 31, 2020 and December 31, 2019 that were designated as hedging instruments for accounting purposes are as follows:
December 31, 2020 December 31, 2019
    Fair Value
Instrument Balance Sheet Location Assets Liabilities Assets Liabilities
    (In millions)
Interest rate swaps Other Current $ —  $ 6  $ —  $ 1 
Interest rate swaps Other —  —  —  2 
Total gross interest rate derivatives (1)
$ —  $ 6  $ —  $ 3 
_____________________
(1)All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of December 31, 2020.

34
Exhibit 99.01
Income Statement Presentation Related to Derivative Instruments
 
The following table presents the effect of derivative instruments on the Partnership’s Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018:
 
Amounts Recognized in Income
Year Ended December 31,
2020 2019 2018
  (In millions)
Natural Gas
Financial futures/swaps gains (losses) $ 4  $ 13  $ (8)
Financial swaptions gains (losses) (2) —  — 
Physical purchases/sales gains —  2  7 
Crude oil (for condensate)
Financial futures/swaps gains (losses) 10  (41) 6 
Natural gas liquids
Financial futures/swaps gains (losses) (2) 42  6 
Total $ 10  $ 16  $ 11 
 
For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2020, 2019 and 2018 are reported in Product sales. For derivatives designated as hedges, amounts recognized in income and reported in Interest expense for the years ended December 31, 2020 and 2019 were approximately $4 million and zero, respectively.

The following table presents the components of gain (loss) on derivative activity in the Partnership’s Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018: 
Year Ended December 31,
2020 2019 2018
  (In millions)
Change in fair value of derivatives $ (13) $ (11) $ 26 
Realized gain (loss) on derivatives 23  27  (15)
Gain on derivative activity $ 10  $ 16  $ 11 

Credit-Risk Related Contingent Features in Derivative Instruments
 
In the event Moody’s or S&P were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, the Partnership could be required to provide additional credit assurances to third parties, which could include letters or credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of December 31, 2020, under these obligations, the Partnership has posted no cash collateral related to natural gas swaps and swaptions, crude oil swaps and swaptions, and NGL swaps and less than $1 million of additional collateral would be required to be posted by the Partnership in the event of a credit ratings downgrade to a below investment grade rating. In certain situations where the Partnership’s credit rating is lowered by Moody’s or S&P, the Partnership could be subject to an early termination event related to certain derivative instruments, which could result in a cash settlement of the instruments at market values on the date of such early termination.



35
Exhibit 99.01
(14) Fair Value Measurements

Certain assets and liabilities are recorded at fair value in the Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows:

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on either the NYMEX or the ICE and settled through either a NYMEX or ICE clearing broker.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 generally include over-the-counter natural gas swaps, natural gas swaptions, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX or the ICE pricing, over-the-counter WTI crude oil swaps and swaptions for condensate sales, and over-the-counter interest rate swaps traded in observable markets with less volume and transaction frequency than active markets. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data.

The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX, ICE or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX or ICE published market prices may be considered Level 1 if they are settled through a NYMEX or ICE clearing broker account with daily margining. Over-the-counter derivatives with NYMEX, ICE or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. Certain derivatives with option features may be classified as Level 2 if valued using an industry standard Black-Scholes option pricing model that contain observable inputs in the marketplace throughout the term of the derivative instrument. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3. As of December 31, 2020, there were no contracts classified as Level 3.
 
The Partnership determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the year ended December 31, 2020, there were no transfers between levels.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on S&P’s and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

36
Exhibit 99.01
Estimated Fair Value of Financial Instruments

The fair values of all accounts receivable, notes receivable, accounts payable, commercial paper and other such financial instruments on the Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts due to their short-term nature and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments at December 31, 2020 and 2019:
 
December 31, 2020 December 31, 2019
Carrying Amount Fair Value Carrying Amount Fair Value
(In millions)
Debt
Revolving Credit Facility (Level 2) (1)
$ —  $ —  $ —  $ — 
2019 Term Loan Agreement (Level 2) 800  800  800  800 
2024 Notes (Level 2) 600  612  600  614 
2027 Notes (Level 2) 698  709  698  698 
2028 Notes (Level 2) 795  817  795  811 
2029 Notes (Level 2) 546  544  549  526 
2044 Notes (Level 2) 531  499  550  506 
EOIT Senior Notes (Level 2) —  —  251  252 
______________________
(1)    Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $250 million and $155 million of commercial paper was outstanding as of December 31, 2020 and 2019, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes, 2044 Notes, and EOIT Senior Notes, is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). As of December 31, 2020, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.

Based upon review of forecasted undiscounted cash flows as of December 31, 2020, all of the asset groups were considered recoverable. Based upon review for other than temporary declines in fair value, the investment in equity method affiliate was considered recoverable. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions including the oversupply of crude oil, NGLs and natural gas as well as the ongoing COVID-19 pandemic and the economic effects of the pandemic, could reduce forecast undiscounted cash flows for the asset groups and result in other than temporary declines in the fair value of the investment in equity method affiliate.

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

37
Exhibit 99.01
As of December 31, 2020 and 2019, the Partnership’s Level 2 interest rate derivatives are recorded as liabilities with no netting adjustments. As of December 31, 2020 and 2019, there were no Level 3 commodity contracts. The following tables summarize the Partnership’s other assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2020 and 2019:
 
December 31, 2020 Commodity Contracts
Gas Imbalances (1)
Assets Liabilities
Assets (2)
Liabilities (3)
(In millions)
Quoted market prices in active market for identical assets (Level 1) $ 2  $ 14  $ —  $ — 
Significant other observable inputs (Level 2) 17  7  23  16 
Total fair value 19  21  23  16 
Netting adjustments (19) (19) —  — 
Total $ —  $ 2  $ 23  $ 16 

December 31, 2019 Commodity Contracts
Gas Imbalances (1)
Assets Liabilities
Assets (2)
Liabilities (3)
(In millions)
Quoted market prices in active market for identical assets (Level 1) $ 5  $ 31  $ —  $ — 
Significant other observable inputs (Level 2) 44  7  14  11 
Total fair value 49  38  14  11 
Netting adjustments (37) (37) —  — 
Total $ 12  $ 1  $ 14  $ 11 
______________________
(1)The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. There were no netting adjustments as of December 31, 2020 and 2019.
(2)Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $19 million and $21 million at December 31, 2020 and 2019, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.
(3)Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $3 million and $8 million at December 31, 2020 and 2019, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.


(15) Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:
Year Ended December 31,
2020 2019 2018
(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest $ 180  $ 185  $ 148 
Income tax, net of refunds 1  1  3 
Non-cash transactions:
Accounts payable related to capital expenditures 9  10  54 
Lease liabilities related to (derecognition) recognition of right-of-use assets (5) 45  — 
Impact of adoption of financial instruments-credit losses accounting standard (Note 1) (3) —  — 

38
Exhibit 99.01
(16) Related Party Transactions

The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.

Transportation and Storage Agreements

Transportation and Storage Agreements with CenterPoint Energy

MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana. As part of the MRT rate case settlements, contracts for these services were extended and are in effect through July 31, 2028 and will remain in effect thereafter unless and until terminated by either party upon twelve months’ prior written notice.

EGT provides natural gas transportation and storage services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas under a combination of contracts that include the following types of services: firm transportation, firm transportation with seasonal demand, firm storage, firm no-notice transportation with storage and maximum rate firm transportation. The firm transportation, firm transportation with seasonal demand, firm storage and no-notice transportation with storage contracts were extended and have terms running through March 31, 2030. The maximum rate firm transportation contracts were also extended and have terms running through March 31, 2024.

The Partnership may agree to reimburse the costs that its customers incur to make required modifications for the repair and maintenance of pipelines that impact customer delivery points. We reimbursed CenterPoint Energy’s LDCs less than $1 million for the year ended December 31, 2020, and $2 million for the year ended December 31, 2019, in connection with receipt facility modifications that were necessitated by the repair and maintenance of our pipelines. For the year ended December 31, 2018, we reimbursed CenterPoint Energy’s LDCs $1 million in connection with a reimbursement associated with an unplanned pipeline outage.

Transportation and Storage Agreements with OGE Energy
 
EOIT provides no-notice load-following transportation and storage services to four of OGE Energy’s generating facilities. Service is provided to three generating facilities under a transportation agreement with a primary term through May 1, 2024, which will remain in effect from year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period. Service is provided to one additional generating facility in Muskogee, Oklahoma under a transportation agreement with a primary term through December 1, 2038. EOIT paid OGE Energy $2 million and waived $5 million of demand fee charges as a result of damage that occurred to the Muskogee facility during commissioning as a result of the failure of certain filters on the connected transportation pipeline, which is included in the Partnership’s results of operations as of December 31, 2019.

Gas Sales and Purchases Transactions

The Partnership sells natural gas volumes to affiliates of CenterPoint Energy and OGE Energy or purchases natural gas volumes from affiliates of CenterPoint Energy through a combination of forward, monthly and daily transactions. The Partnership enters into these physical natural gas transactions in the normal course of business based upon relevant market prices.

The Partnership’s revenues from affiliated companies accounted for 6%, 6% and 5% of total revenues during the years ended December 31, 2020, 2019 and 2018, respectively. Amounts of total revenues from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows:
 
Year Ended December 31,
2020 2019 2018
(In millions)
Gas transportation and storage service revenues — CenterPoint Energy $ 100  $ 108  $ 111 
Natural gas product sales — CenterPoint Energy 1  8  11 
Gas transportation and storage service revenues — OGE Energy 38  41  37 
Natural gas product sales — OGE Energy
10  10  4 
Total revenues — affiliated companies $ 149  $ 167  $ 163 
39
Exhibit 99.01

Amounts of natural gas purchased from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows:
Year Ended December 31,
2020 2019 2018
(In millions)
Cost of natural gas purchases — CenterPoint Energy $ 1  $ —  $ 3 
Cost of natural gas purchases — OGE Energy 24  33  23 
Total cost of natural gas purchases — affiliated companies $ 25  $ 33  $ 26 

Corporate services, operating lease expense and seconded employee

The Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under services agreements for an initial term that ended on April 30, 2016. The services agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice prior to the end of any extension. Additionally, the Partnership may terminate these services agreements at any time with 180 days’ notice, if approved by the Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2020 are less than $1 million and $1 million, respectively.

The Partnership leased office and data center space from an affiliate of CenterPoint Energy in Shreveport, Louisiana. The term of the lease was effective on October 1, 2016 and ended on December 31, 2019.

During the years ended December 31, 2020, 2019 and 2018, the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for seconded employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at actual cost subject to a cap of $5 million in 2020 and thereafter, unless and until secondment is terminated.

Amounts charged to the Partnership by affiliates for corporate services, operating lease and seconded employees, are primarily included in Operation and maintenance expenses and General and administrative expenses in the Partnership’s Consolidated Statements of Income are as follows:
 
Year Ended December 31,
2020 2019 2018
(In millions)
Corporate Services — CenterPoint Energy $ —  $ —  $ 1 
Operating Lease — CenterPoint Energy —  1  1 
Seconded Employee Costs — OGE Energy 17  18  29 
Corporate Services — OGE Energy —  —  1 
Total corporate services, operating lease and seconded employee expense $ 17  $ 19  $ 32 


(17) Commitments and Contingencies
 
Legal, Regulatory and Other Matters

The Partnership is involved in legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Partnership regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Partnership does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.
40
Exhibit 99.01

Commercial Obligations

On January 1, 2017, the Partnership entered into a 10-year gathering and processing agreement, which became effective on July 1, 2018, with an affiliate of Energy Transfer, LP for 400 MMcf/d of deliveries to the Godley Plant in Johnson County, Texas. As of December 31, 2020, the Partnership estimates the remaining associated minimum volume commitment fee to be $172 million in the aggregate. Minimum volume commitment fees are expected to be $23 million per year from 2021 through 2027 and $11 million in 2028.

On September 13, 2018, the Partnership executed a precedent agreement for the development of the Gulf Run Pipeline, an interstate natural gas transportation project. On January 30, 2019, a final investment decision was made by Golden Pass LNG, the cornerstone shipper for the LNG facility to be served by the Gulf Run Pipeline project. Subject to approval of the project by FERC, the Partnership will be required to construct a large-diameter pipeline from northern Louisiana to Gulf Coast markets. In addition, the Partnership requested approval to transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. The Partnership filed applications with FERC to obtain authorization to construct and operate the pipeline on February 28, 2020. FERC issued the environmental assessment on October 29, 2020. Under the precedent agreement, the Partnership estimates the cost to complete the Gulf Run Pipeline project would be as much as $500 million. The project is backed by a 20-year firm transportation service agreement. The Gulf Run Pipeline connects natural gas producing regions in the U.S., including the Haynesville, Marcellus, Utica and Barnett shales and the Mid-Continent region. The project is expected to be placed into service in late 2022.


(18) Income Tax

The Partnership’s earnings are generally not subject to income tax (other than Texas state margin tax and taxes associated with the Partnership’s corporate subsidiary Enable Midstream Services) and are taxable at the individual partner level. The Partnership and its non-corporate subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income tax in the Consolidated Financial Statements. Consequently, the Consolidated Statements of Income do not include an income tax provision (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary).

The items comprising income tax expense are as follows:
  Year Ended December 31,
  2020 2019 2018
  (In millions)
Provision for current income tax
Federal $ (2) $ —  $ — 
State 1  —  — 
Total provision for current income tax (1) —  — 
Benefit for deferred income tax, net
Federal $ 1  $ (1) $ (1)
State —  —  — 
Total benefit for deferred income tax, net 1  (1) (1)
Total income tax benefit $ —  $ (1) $ (1)
 
41
Exhibit 99.01
The components of Deferred Income Tax as of December 31, 2020 and 2019 were as follows:
  December 31,
  2020 2019
  (In millions)
Deferred tax liabilities, net:
Non-current:
Intercompany management fee $ 16  $ 17 
Depreciation 5  6 
Net operating loss (1) (2)
Accrued compensation (15) (17)
Total deferred tax liabilities, net $ 5  $ 4 

Uncertain Income Tax Positions

There were no unrecognized tax benefits as of December 31, 2020, 2019 and 2018.

Tax Audits and Settlements

The federal income tax return of the Partnership has been audited through the 2013 tax year.

Net Operating Losses

The Partnership’s corporate subsidiary, Enable Midstream Services, has federal and state net operating losses (NOL) the tax benefits of which are recorded as deferred tax assets. As of December 31, 2020, the Partnership had approximately $4 million of Federal NOLs, which can be carried forward indefinitely and approximately $8 million of various State NOLs, of which approximately $2 million will expire between 2023 and 2039. Additionally, as of December 31, 2020, the Partnership had a deferred tax asset related to Federal and State NOLs of $1 million and zero, respectively.


(19) Equity-Based Compensation

Enable GP has adopted the Enable Midstream Partners, LP Long Term Incentive Plan (LTIP) for officers, directors and employees of the Partnership and its affiliates, including any individual who provides services to the Partnership as a seconded employee. The LTIP provides for the following types of awards: restricted units, phantom units, appreciations rights, option rights, cash incentive awards, performance units, distribution equivalent rights, and other awards denominated in, payable in, valued in or otherwise based on or related to common units.

The LTIP is administered by the Compensation Committee of the Board of Directors. With respect to any grant of equity as long-term incentive awards to our independent directors and our officers subject to reporting under Section 16 of the Exchange Act, the Compensation Committee makes recommendations to the Board of Directors and any such awards will only be effective upon the approval of the Board of Directors. The LTIP limits the number of units that may be delivered pursuant to vested awards to 13,100,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units cancelled, forfeited, expired or cash settled are available for delivery pursuant to other awards.

The Board of Directors may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made, including amending the long-term incentive plan to increase the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would be adverse to the participant without the consent of the participant.

42
Exhibit 99.01
Performance unit, restricted unit and phantom unit awards are classified as equity on the Partnership’s Consolidated Balance Sheets. The following table summarizes the Partnership’s equity-based compensation expense for the years ended December 31, 2020, 2019 and 2018 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:
Year Ended December 31,
2020 2019 2018
(In millions)
Performance units $ 7  $ 9  $ 9 
Restricted units —  —  1 
Phantom units 6  7  6 
Total equity-based compensation expense $ 13  $ 16  $ 16 

Performance Units

Awards of performance based phantom units (performance units) have been made under the LTIP in 2020, 2019 and 2018 to certain officers and employees providing services to the Partnership. Subject to the achievement of performance goals, the performance unit awards cliff vest three years from the grant date, with distribution equivalent rights paid at vesting. The performance goals for 2020, 2019 and 2018 awards are based on total unitholder return over a three-calendar year performance cycle. Total unitholder return is based on the relative performance of the Partnership’s common units against a peer group. The performance unit awards have a payout from zero to 200% of the target based on the level of achievement of the performance goal. Performance unit awards are paid out in common units, with distribution equivalent rights paid in cash at vesting. Any unearned performance units are cancelled. Pay out requires the confirmation of the achievement of the performance level by the Compensation Committee. Prior to vesting, performance units are subject to forfeiture if the recipient’s employment with the Partnership is terminated for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control. In the event of retirement, a participant will receive a prorated payment based on the target performance or a prorated payment based on the actual performance of the performance goals during the award cycle, based on the grant year.

The fair value of each performance unit award was estimated on the grant date using a lattice-based valuation model. The valuation information factored into the model includes the expected distribution yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition over the expected life of the performance units. Equity-based compensation expense for each performance unit award is a fixed amount determined at the grant date fair value and is recognized over the three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Distributions are accumulated and paid at vesting and, therefore, are included in the fair value calculation of the performance unit award. The expected price volatility for the awards granted in 2020, 2019 and 2018 is based on three years of daily stock price observations, to determine the total unitholder return ranking. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. There are no post-vesting restrictions related to the Partnership’s performance units.

The number of performance units granted based on total unitholder return and the assumptions used to calculate the grant date fair value of the performance units based on total unitholder return are shown in the following table.
2020 2019 2018
Number of units granted 933,738  638,798  551,742 
Fair value of units granted $ 7.00  $ 19.95  $ 17.70 
Expected price volatility 27.7  % 34.2  % 44.2  %
Risk-free interest rate 0.85  % 2.54  % 2.36  %
Distribution yield 12.27  % 8.38  % 8.56  %
Expected life of units (in years) 3 3 3

Phantom Units

Awards of phantom units have been made under the LTIP in 2020, 2019 and 2018 to certain officers and employees providing services to the Partnership. Except for phantom units granted to retirement eligible employees, which vest in annual tranches, phantom units cliff-vest on the first, second or third anniversary of the grant date with distribution equivalent rights
43
Exhibit 99.01
paid during the vesting period. Phantom unit awards are paid out in common units, with distribution equivalent rights paid in cash. Any unearned phantom units are cancelled. Prior to vesting, phantom units are subject to forfeiture if the recipient’s employment with the Partnership is terminated for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control.

The fair value of the phantom units was based on the closing market price of the Partnership’s common unit on the grant date. Equity-based compensation expense for the phantom unit is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over the vesting period. Distributions on phantom units are paid during the vesting period and, therefore, are included in the fair value calculation. The expected life of the phantom unit is based on the applicable vesting period. The number of phantom units granted and the grant date fair value are shown in the following table.
2020 2019 2018
Phantom units granted 1,002,345  695,486  546,708 
Fair value of phantom units granted
$2.67 - $10.13
$8.95 - $15.04
$13.74 - $17.00

Other Awards

In 2020, 2019 and 2018, the Board of Directors granted common units to the independent directors of Enable GP, for their service as directors, which vested immediately. The fair value of the common units was based on the closing market price of the Partnership’s common unit on the grant date.
2020 2019 2018
Common units granted 63,963  28,221  16,335 
Fair value of common units granted $ 4.23  $ 10.43  $ 14.94 

Units Outstanding

A summary of the activity for the Partnership’s performance units and phantom units as of December 31, 2020 and changes during 2020 are shown in the following table.
  Performance Units Phantom Units
Number
of Units 		Weighted Average
Grant-Date
Fair Value,
Per Unit 		Number
of Units 		Weighted Average
Grant-Date
Fair Value,
Per Unit
  (In millions, except unit data)
Units outstanding at 12/31/2019 1,393,329  $ 19.04  1,392,560  $ 14.65 
Granted (1)
933,738  7.00  1,002,345  6.44 
Vested (2)(3)
(390,079) 19.21  (399,406) 15.76 
Forfeited (171,480) 14.25  (204,654) 10.46 
Units outstanding at 12/31/2020 1,765,508  13.10  1,790,845  $ 10.29 
Aggregate intrinsic value of units outstanding at December 31, 2020 $ 9  $ 9 
_____________________
(1)For performance units, this represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0% to 200% of the target.
(2)Performance units vested as of December 31, 2020 include 376,292 from the 2017 annual grant, which were approved by the Board of Directors in 2017 and, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2017 through December 31, 2019, no performance units vested.
(3)Performance units outstanding as of December 31, 2020 include 389,817 units from the 2018 annual grants, which were approved by the Board of Directors in 2018 and, based on the level of achievement of a performance goal established by the Board of Directors over a performance period of January 1, 2018 through December 31, 2020, will vest at 0%. The decrease in outstanding units for a payout percentage of an amount other than 100% is not reflected above until the vesting date.


44
Exhibit 99.01
A summary of the Partnership’s performance, restricted and phantom units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for each of the years ended December 31, 2020, 2019 and 2018 are shown in the following tables.
Year Ended December 31, 2020
  Performance Units Restricted Stock Phantom Units
  (In millions)
Aggregate intrinsic value of units vested $ —  $ —  $ 3 
Fair value of units vested 7  —  6 

Year Ended December 31, 2019
  Performance Units Restricted Stock Phantom Units
  (In millions)
Aggregate intrinsic value of units vested $ 34  $ —  $ 9 
Fair value of units vested 13  —  5 

Year Ended December 31, 2018
  Performance Units Restricted Stock Phantom Units
  (In millions)
Aggregate intrinsic value of units vested $ 11  $ 3  $ 1 
Fair value of units vested 7  4  — 

Unrecognized Compensation Expense

A summary of the Partnership’s unrecognized compensation expense for its non-vested performance units and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.
December 31, 2020
Unrecognized Compensation Cost
(In millions) 		Weighted Average Period for Recognition
(In years)
Performance Units $ 9  1.43
Phantom Units 6  1.30
Total $ 15 

As of December 31, 2020, there were 5,234,214 units available for issuance under the long-term incentive plan.


(20) Reportable Segments
 
The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies described in Note 1. The Partnership uses operating income as the measure of profit or loss for its reportable segments.
 
The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. Our transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers.

45
Exhibit 99.01
Financial data for reportable segments are as follows:
Year Ended December 31, 2020 Gathering and
Processing
Transportation
and Storage (1)
Eliminations Total
  (In millions)
Product sales $ 1,087  $ 340  $ (295) $ 1,132 
Service revenues 799  541  (9) 1,331 
Total Revenues 1,886  881  (304) 2,463 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 936  332  (303) 965 
Operation and maintenance, General and administrative 334  183  (1) 516 
Depreciation and amortization 299  121  —  420 
Impairments of property, plant and equipment and goodwill 28  —  —  28 
Taxes other than income tax 42  27  —  69 
Operating Income $ 247  $ 218  $ —  $ 465 
Total Assets $ 10,830  $ 5,729  $ (4,830) $ 11,729 
Capital expenditures $ 107  $ 108  $ —  $ 215 

Year Ended December 31, 2019 Gathering and
Processing
Transportation
and Storage (1)
Eliminations Total
  (In millions)
Product sales $ 1,449  $ 487  $ (403) $ 1,533 
Service revenues 889  551  (13) 1,427 
Total Revenues 2,338  1,038  (416) 2,960 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 1,203  491  (415) 1,279 
Operation and maintenance, General and administrative 320  207  (1) 526 
Depreciation and amortization 308  125  —  433 
Impairments of property, plant and equipment and goodwill 86  —  —  86 
Taxes other than income tax 41  26  —  67 
Operating Income $ 380  $ 189  $ —  $ 569 
Total Assets $ 9,739  $ 5,886  $ (3,359) $ 12,266 
Capital expenditures $ 314  $ 118  $ —  $ 432 
46
Exhibit 99.01
Year Ended December 31, 2018 Gathering and
Processing
Transportation
and Storage (1)
Eliminations Total
  (In millions)
Product sales $ 2,016  $ 625  $ (535) $ 2,106 
Service revenues 802  537  (14) 1,325 
Total Revenues 2,818  1,162  (549) 3,431 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 1,741  628  (550) 1,819 
Operation and maintenance, General and administrative 312  189  —  501 
Depreciation and amortization 263  135  —  398 
Taxes other than income tax 38  27  —  65 
Operating Income $ 464  $ 183  $ 1  $ 648 
Total Assets $ 9,874  $ 5,805  $ (3,235) $ 12,444 
Capital expenditures, including acquisitions $ 981  $ 190  $ —  $ 1,171 
_____________________
(1)See Note 11 for discussion regarding ownership interests in SESH and related equity earnings (losses) included in the transportation and storage reportable segment for the years ended December 31, 2020, 2019 and 2018.



(21) Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2020 and 2019 are as follows:
Quarters Ended
March 31, 2020 June 30, 2020 September 30, 2020 December 31, 2020
(in millions, except per unit data)
Total Revenues $ 648  $ 515  $ 596  $ 704 
Cost of natural gas and natural gas liquids 226  177  250  312 
Operating income 146  80  100  139 
Net income (loss) (1)
105  44  (163) 97 
Net income (loss) attributable to limited partners 112  44  (164) 96 
Net income (loss) attributable to common units 103  35  (173) 87 
Basic and diluted earnings per unit
Basic $ 0.24  $ 0.08  $ (0.40) $ 0.20 
Diluted $ 0.19  $ 0.08  $ (0.40) $ 0.19 
47
Exhibit 99.01
Quarters Ended
March 31, 2019 June 30, 2019 September 30, 2019 December 31, 2019
(in millions, except per unit data)
Total Revenues $ 795  $ 735  $ 699  $ 731 
Cost of natural gas and natural gas liquids
378  317  263  321 
Operating income (2)
165  167  175  62 
Net income 123  124  133  20 
Net income attributable to limited partners
122  124  132  18 
Net income attributable to common units
113  115  123  9 
Basic and diluted earnings per unit
Basic $ 0.26  $ 0.26  $ 0.28  $ 0.02 
Diluted $ 0.26  $ 0.26  $ 0.28  $ 0.02 
 _____________________
(1)The Partnership recorded an impairment of $225 million in Equity in earnings (losses) of equity method affiliate, net during the third quarter related to its investment in SESH. See Note 11 for further information.
(2)The Partnership recorded impairments to goodwill of $12 million and $86 million during the first quarter 2020 related to the Ark-La-Tex Basin reporting unit and the fourth quarter of 2019 related to the Anadarko Basin reporting unit, respectively, included in the gathering and processing reportable segment. See Note 10 for further information.


(22) Subsequent Event

On February 17, 2021, the Partnership and Energy Transfer announced their entry into a definitive merger agreement pursuant to which Energy Transfer, through wholly owned subsidiaries, will acquire the Partnership. Under the terms of the merger agreement, the Partnership’s common unitholders will receive 0.8595 of one common unit representing limited partner interests in Energy Transfer in exchange for each Partnership common unit. In addition, each issued and outstanding Series A preferred unit of the Partnership will be exchanged for 0.0265 of an Energy Transfer Series G preferred unit, and Energy Transfer will make a $10 million cash payment for the limited liability company interests in the Partnership’s general partner.

The transaction has been approved by the Conflicts Committee and the Board of Directors of Enable GP. CenterPoint Energy and OGE Energy, who collectively own approximately 79.2% of Partnership common units, have entered into support agreements pursuant to which they have agreed to vote their common units in favor of the merger. The transaction is subject to the satisfaction of customary closing conditions.


48