10-Q 1 pcg-20220331.htm 10-Q pcg-20220331
false2022Q1PG&E CORP0001004980--12-31PACIFIC GAS & ELECTRIC COfalse000007548834 years, 11 months00010049802022-01-012022-03-310001004980pcg:PacificGasElectricCoMember2022-01-012022-03-310001004980exch:XNYSpcg:CommonStockNoParValueMember2022-01-012022-03-310001004980exch:XNYSpcg:EquityUnitsMember2022-01-012022-03-310001004980pcg:FirstPreferredStockCumulativeParValue25PerShare5SeriesARedeemableMemberpcg:NYSEAMERICANLLCMember2022-01-012022-03-310001004980pcg:NYSEAMERICANLLCMemberpcg:FirstPreferredStockCumulativeParValue25PerShare5RedeemableMember2022-01-012022-03-310001004980pcg:NYSEAMERICANLLCMemberpcg:FirstPreferredStockCumulativeParValue25PerShare4.80RedeemableMember2022-01-012022-03-310001004980pcg:NYSEAMERICANLLCMemberpcg:FirstPreferredStockCumulativeParValue25PerShare4.50RedeemableMember2022-01-012022-03-310001004980pcg:FirstPreferredStockCumulativeParValue25PerShare4.36SeriesARedeemableMemberpcg:NYSEAMERICANLLCMember2022-01-012022-03-310001004980pcg:NYSEAMERICANLLCMemberpcg:FirstPreferredStockCumulativeParValue25PerShare6NonredeemableMember2022-01-012022-03-310001004980pcg:NYSEAMERICANLLCMemberpcg:FirstPreferredStockCumulativeParValue25PerShare5.50NonredeemableMember2022-01-012022-03-310001004980pcg:NYSEAMERICANLLCMemberpcg:FirstPreferredStockCumulativeParValue25PerShare5NonredeemableMember2022-01-012022-03-3100010049802022-04-21xbrli:shares0001004980pcg:PacificGasElectricCoMember2022-04-210001004980pcg:WMCEInterimRateReliefMember2020-09-30iso4217:USD0001004980pcg:CEMAInterimRateReliefMember2019-08-070001004980pcg:CEMAInterimRateReliefMember2022-03-170001004980pcg:FireHazardPreventionMemorandumAccountMemberpcg:WMCEInterimRateReliefMember2022-03-310001004980pcg:FireRiskMitigationMemorandumAccountAndWildfireMitigationPlanMemorandumAccountMemberpcg:WMCEInterimRateReliefMember2022-03-310001004980pcg:CatastrophicEventMemorandumAccountMemberpcg:WMCEInterimRateReliefMember2022-03-310001004980pcg:WMCEInterimRateReliefMember2020-10-230001004980pcg:WMCEInterimRateReliefMember2021-09-212021-09-210001004980pcg:WMCEInterimRateReliefMember2021-09-210001004980us-gaap:ElectricityMember2022-01-012022-03-310001004980us-gaap:ElectricityMember2021-01-012021-03-310001004980us-gaap:NaturalGasUsRegulatedMember2022-01-012022-03-310001004980us-gaap:NaturalGasUsRegulatedMember2021-01-012021-03-3100010049802021-01-012021-03-31iso4217:USDxbrli:shares00010049802022-03-3100010049802021-12-310001004980us-gaap:VariableInterestEntityPrimaryBeneficiaryMember2022-03-310001004980us-gaap:VariableInterestEntityPrimaryBeneficiaryMember2021-12-3100010049802020-12-3100010049802021-03-310001004980us-gaap:CommonStockMember2021-12-310001004980us-gaap:TreasuryStockMember2021-12-310001004980us-gaap:RetainedEarningsMember2021-12-310001004980us-gaap:AccumulatedOtherComprehensiveIncomeMember2021-12-310001004980us-gaap:ParentMember2021-12-310001004980us-gaap:NoncontrollingInterestMember2021-12-310001004980us-gaap:RetainedEarningsMember2022-01-012022-03-310001004980us-gaap:ParentMember2022-01-012022-03-310001004980us-gaap:CommonStockMember2022-01-012022-03-310001004980us-gaap:TreasuryStockMember2022-01-012022-03-310001004980us-gaap:CommonStockMember2022-03-310001004980us-gaap:TreasuryStockMember2022-03-310001004980us-gaap:RetainedEarningsMember2022-03-310001004980us-gaap:AccumulatedOtherComprehensiveIncomeMember2022-03-310001004980us-gaap:ParentMember2022-03-310001004980us-gaap:NoncontrollingInterestMember2022-03-310001004980us-gaap:CommonStockMember2020-12-310001004980us-gaap:RetainedEarningsMember2020-12-310001004980us-gaap:AccumulatedOtherComprehensiveIncomeMember2020-12-310001004980us-gaap:ParentMember2020-12-310001004980us-gaap:NoncontrollingInterestMember2020-12-310001004980us-gaap:RetainedEarningsMember2021-01-012021-03-310001004980us-gaap:ParentMember2021-01-012021-03-310001004980us-gaap:AccumulatedOtherComprehensiveIncomeMember2021-01-012021-03-310001004980us-gaap:CommonStockMember2021-01-012021-03-310001004980us-gaap:CommonStockMember2021-03-310001004980us-gaap:RetainedEarningsMember2021-03-310001004980us-gaap:AccumulatedOtherComprehensiveIncomeMember2021-03-310001004980us-gaap:ParentMember2021-03-310001004980us-gaap:NoncontrollingInterestMember2021-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:ElectricityMember2022-01-012022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:ElectricityMember2021-01-012021-03-310001004980us-gaap:NaturalGasUsRegulatedMemberpcg:PacificGasElectricCoMember2022-01-012022-03-310001004980us-gaap:NaturalGasUsRegulatedMemberpcg:PacificGasElectricCoMember2021-01-012021-03-310001004980pcg:PacificGasElectricCoMember2021-01-012021-03-310001004980pcg:PacificGasElectricCoMember2022-03-310001004980pcg:PacificGasElectricCoMember2021-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:VariableInterestEntityPrimaryBeneficiaryMember2022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:VariableInterestEntityPrimaryBeneficiaryMember2021-12-310001004980pcg:PacificGasElectricCoMember2020-12-310001004980pcg:PacificGasElectricCoMember2021-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:PreferredStockMember2021-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:CommonStockMember2021-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:AdditionalPaidInCapitalMember2021-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:RetainedEarningsMember2021-12-310001004980us-gaap:AccumulatedOtherComprehensiveIncomeMemberpcg:PacificGasElectricCoMember2021-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:RetainedEarningsMember2022-01-012022-03-310001004980us-gaap:AccumulatedOtherComprehensiveIncomeMemberpcg:PacificGasElectricCoMember2022-01-012022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:PreferredStockMember2022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:CommonStockMember2022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:AdditionalPaidInCapitalMember2022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:RetainedEarningsMember2022-03-310001004980us-gaap:AccumulatedOtherComprehensiveIncomeMemberpcg:PacificGasElectricCoMember2022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:PreferredStockMember2020-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:CommonStockMember2020-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:AdditionalPaidInCapitalMember2020-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:RetainedEarningsMember2020-12-310001004980us-gaap:AccumulatedOtherComprehensiveIncomeMemberpcg:PacificGasElectricCoMember2020-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:ParentMember2020-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:RetainedEarningsMember2021-01-012021-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:ParentMember2021-01-012021-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:PreferredStockMember2021-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:CommonStockMember2021-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:AdditionalPaidInCapitalMember2021-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:RetainedEarningsMember2021-03-310001004980us-gaap:AccumulatedOtherComprehensiveIncomeMemberpcg:PacificGasElectricCoMember2021-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:ParentMember2021-03-31pcg:numberOfSegmentpcg:notice0001004980pcg:SubrogationWildfireTrustAndFireVictimTrustMember2021-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:ElectricityMemberpcg:ResidentialMember2022-01-012022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:ElectricityMemberpcg:ResidentialMember2021-01-012021-03-310001004980pcg:PacificGasElectricCoMemberpcg:CommercialMemberus-gaap:ElectricityMember2022-01-012022-03-310001004980pcg:PacificGasElectricCoMemberpcg:CommercialMemberus-gaap:ElectricityMember2021-01-012021-03-310001004980pcg:IndustrialMemberpcg:PacificGasElectricCoMemberus-gaap:ElectricityMember2022-01-012022-03-310001004980pcg:IndustrialMemberpcg:PacificGasElectricCoMemberus-gaap:ElectricityMember2021-01-012021-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:ElectricityMemberpcg:AgriculturalMember2022-01-012022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:ElectricityMemberpcg:AgriculturalMember2021-01-012021-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:ElectricityMemberpcg:PublicStreetAndHighwayLightingMember2022-01-012022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:ElectricityMemberpcg:PublicStreetAndHighwayLightingMember2021-01-012021-03-310001004980pcg:PacificGasElectricCoMemberpcg:OtherCustomersMemberus-gaap:ElectricityMember2022-01-012022-03-310001004980pcg:PacificGasElectricCoMemberpcg:OtherCustomersMemberus-gaap:ElectricityMember2021-01-012021-03-310001004980us-gaap:NaturalGasUsRegulatedMemberpcg:PacificGasElectricCoMemberpcg:ResidentialMember2022-01-012022-03-310001004980us-gaap:NaturalGasUsRegulatedMemberpcg:PacificGasElectricCoMemberpcg:ResidentialMember2021-01-012021-03-310001004980us-gaap:NaturalGasUsRegulatedMemberpcg:PacificGasElectricCoMemberpcg:CommercialMember2022-01-012022-03-310001004980us-gaap:NaturalGasUsRegulatedMemberpcg:PacificGasElectricCoMemberpcg:CommercialMember2021-01-012021-03-310001004980us-gaap:NaturalGasUsRegulatedMemberpcg:PacificGasElectricCoMemberpcg:TransportationServiceMember2022-01-012022-03-310001004980us-gaap:NaturalGasUsRegulatedMemberpcg:PacificGasElectricCoMemberpcg:TransportationServiceMember2021-01-012021-03-310001004980us-gaap:NaturalGasUsRegulatedMemberpcg:PacificGasElectricCoMemberpcg:OtherCustomersMember2022-01-012022-03-310001004980us-gaap:NaturalGasUsRegulatedMemberpcg:PacificGasElectricCoMemberpcg:OtherCustomersMember2021-01-012021-03-310001004980pcg:PacificGasElectricCoMemberpcg:ReceivablesSecuritizationProgramMember2022-03-310001004980pcg:PacificGasElectricCoMemberpcg:ReceivablesSecuritizationProgramMemberus-gaap:SubsequentEventMember2022-04-202022-04-200001004980pcg:PacificGasElectricCoMemberpcg:ReceivablesSecuritizationProgramMemberus-gaap:SubsequentEventMember2022-04-200001004980pcg:ReceivablesSecuritizationProgramMemberpcg:PGEARFacilityLLCMember2022-03-310001004980pcg:ReceivablesSecuritizationProgramMemberpcg:PGEARFacilityLLCMember2021-12-310001004980pcg:PacificGasElectricCoMemberpcg:ReceivablesSecuritizationProgramMember2021-12-310001004980pcg:RecoveryBondsMemberus-gaap:SecuredDebtMember2021-11-120001004980pcg:RecoveryBondsMemberus-gaap:SecuredDebtMemberpcg:TrancheOneMember2021-11-12xbrli:pure0001004980pcg:TrancheTwoMemberpcg:RecoveryBondsMemberus-gaap:SecuredDebtMember2021-11-120001004980pcg:TrancheThreeMemberpcg:RecoveryBondsMemberus-gaap:SecuredDebtMember2021-11-120001004980pcg:RecoveryBondsMemberus-gaap:SecuredDebtMember2022-03-310001004980pcg:RecoveryBondsMemberus-gaap:SecuredDebtMember2021-12-310001004980pcg:WildfireFundAssetMember2022-01-012022-03-310001004980us-gaap:OtherCurrentLiabilitiesMember2022-03-310001004980us-gaap:OtherNoncurrentAssetsMemberpcg:DixieFire2021Member2022-03-310001004980us-gaap:PensionPlansDefinedBenefitMember2022-01-012022-03-310001004980us-gaap:PensionPlansDefinedBenefitMember2021-01-012021-03-310001004980us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2022-01-012022-03-310001004980us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2021-01-012021-03-310001004980us-gaap:PensionPlansDefinedBenefitMemberus-gaap:AociIncludingPortionAttributableToNoncontrollingInterestMember2021-12-310001004980us-gaap:AociIncludingPortionAttributableToNoncontrollingInterestMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2021-12-310001004980us-gaap:AociIncludingPortionAttributableToNoncontrollingInterestMember2021-12-310001004980us-gaap:PensionPlansDefinedBenefitMemberus-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember2022-01-012022-03-310001004980us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember2022-01-012022-03-310001004980us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember2022-01-012022-03-310001004980us-gaap:PensionPlansDefinedBenefitMemberus-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember2022-01-012022-03-310001004980us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2022-01-012022-03-310001004980us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember2022-01-012022-03-310001004980us-gaap:PensionPlansDefinedBenefitMemberus-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetTransitionIncludingPortionAttributableToNoncontrollingInterestMember2022-01-012022-03-310001004980us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetTransitionIncludingPortionAttributableToNoncontrollingInterestMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2022-01-012022-03-310001004980us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetTransitionIncludingPortionAttributableToNoncontrollingInterestMember2022-01-012022-03-310001004980us-gaap:PensionPlansDefinedBenefitMemberus-gaap:AociIncludingPortionAttributableToNoncontrollingInterestMember2022-03-310001004980us-gaap:AociIncludingPortionAttributableToNoncontrollingInterestMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2022-03-310001004980us-gaap:AociIncludingPortionAttributableToNoncontrollingInterestMember2022-03-310001004980us-gaap:PensionPlansDefinedBenefitMemberus-gaap:AociIncludingPortionAttributableToNoncontrollingInterestMember2020-12-310001004980us-gaap:AociIncludingPortionAttributableToNoncontrollingInterestMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-310001004980us-gaap:AociIncludingPortionAttributableToNoncontrollingInterestMember2020-12-310001004980us-gaap:PensionPlansDefinedBenefitMemberus-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember2021-01-012021-03-310001004980us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember2021-01-012021-03-310001004980us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetPriorServiceIncludingPortionAttributableToNoncontrollingInterestMember2021-01-012021-03-310001004980us-gaap:PensionPlansDefinedBenefitMemberus-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember2021-01-012021-03-310001004980us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2021-01-012021-03-310001004980us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetGainLossIncludingPortionAttributableToNoncontrollingInterestMember2021-01-012021-03-310001004980us-gaap:PensionPlansDefinedBenefitMemberus-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetTransitionIncludingPortionAttributableToNoncontrollingInterestMember2021-01-012021-03-310001004980us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetTransitionIncludingPortionAttributableToNoncontrollingInterestMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2021-01-012021-03-310001004980us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetTransitionIncludingPortionAttributableToNoncontrollingInterestMember2021-01-012021-03-310001004980us-gaap:PensionPlansDefinedBenefitMemberus-gaap:AociIncludingPortionAttributableToNoncontrollingInterestMember2021-03-310001004980us-gaap:AociIncludingPortionAttributableToNoncontrollingInterestMemberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2021-03-310001004980us-gaap:AociIncludingPortionAttributableToNoncontrollingInterestMember2021-03-310001004980pcg:RegulatoryBalancingAccountsReceivableMemberpcg:ResidentialUncollectiblesBalancingAccountsMember2022-03-310001004980pcg:COVID19PandemicProtectionMemorandumAccountMember2022-03-310001004980us-gaap:PensionCostsMember2022-03-310001004980us-gaap:PensionCostsMember2021-12-310001004980pcg:EnvironmentalComplianceCostsMember2022-03-310001004980pcg:EnvironmentalComplianceCostsMember2021-12-310001004980pcg:UtilityRetainedGenerationMember2022-03-310001004980pcg:UtilityRetainedGenerationMember2021-12-310001004980pcg:PriceRiskManagementMember2022-03-310001004980pcg:PriceRiskManagementMember2021-12-310001004980pcg:CatastrophicEventMemorandumAccountMember2022-03-310001004980pcg:CatastrophicEventMemorandumAccountMember2021-12-310001004980pcg:WildfireExpenseMemorandumAccountMember2022-03-310001004980pcg:WildfireExpenseMemorandumAccountMember2021-12-310001004980pcg:FireHazardPreventionMemorandumAccountMember2022-03-310001004980pcg:FireHazardPreventionMemorandumAccountMember2021-12-310001004980pcg:FireRiskMitigationMemorandumAccountMember2022-03-310001004980pcg:FireRiskMitigationMemorandumAccountMember2021-12-310001004980pcg:WildFireMitigationPlanMemorandumAccountMember2022-03-310001004980pcg:WildFireMitigationPlanMemorandumAccountMember2021-12-310001004980us-gaap:DeferredIncomeTaxChargesMember2022-03-310001004980us-gaap:DeferredIncomeTaxChargesMember2021-12-310001004980pcg:InsurancePremiumCostsMember2022-03-310001004980pcg:InsurancePremiumCostsMember2021-12-310001004980pcg:WildfireMitigationBalancingAccountMember2022-03-310001004980pcg:WildfireMitigationBalancingAccountMember2021-12-310001004980pcg:VegetationManagementBalancingAccountMember2022-03-310001004980pcg:VegetationManagementBalancingAccountMember2021-12-310001004980pcg:COVID19PandemicProtectionMemorandumAccountMember2021-12-310001004980pcg:MicrogridMemorandumAccountMember2022-03-310001004980pcg:MicrogridMemorandumAccountMember2021-12-310001004980pcg:FinancingCostsMember2022-03-310001004980pcg:FinancingCostsMember2021-12-310001004980us-gaap:OtherRegulatoryAssetsLiabilitiesMember2022-03-310001004980us-gaap:OtherRegulatoryAssetsLiabilitiesMember2021-12-310001004980pcg:CatastrophicEventMemorandumAccountMemberpcg:COVID19Member2022-03-310001004980pcg:CatastrophicEventMemorandumAccountMemberpcg:COVID19Member2021-12-310001004980pcg:WildfireMitigationBalancingAccountMembersrt:MinimumMember2022-01-012022-03-310001004980pcg:VegetationManagementBalancingAccountMembersrt:MinimumMember2022-01-012022-03-310001004980pcg:COVID19PandemicProtectionMemorandumAccountUndercollectionBadDebtMember2022-03-310001004980pcg:COVID19PandemicProtectionMemorandumAccountProgramAndAccountsReceivableFinancingCostsMember2022-03-310001004980pcg:COVID19PandemicProtectionMemorandumAccountUndercollectionBadDebtMember2021-12-310001004980pcg:COVID19PandemicProtectionMemorandumAccountProgramAndAccountsReceivableFinancingCostsMember2021-12-310001004980pcg:CostOfRemovalObligationMember2022-03-310001004980pcg:CostOfRemovalObligationMember2021-12-310001004980pcg:RecoveriesInExcessOfAroMember2022-03-310001004980pcg:RecoveriesInExcessOfAroMember2021-12-310001004980pcg:PublicPurposeProgramsMember2022-03-310001004980pcg:PublicPurposeProgramsMember2021-12-310001004980us-gaap:PostretirementBenefitCostsMember2022-03-310001004980us-gaap:PostretirementBenefitCostsMember2021-12-310001004980pcg:TowerLicensesMember2022-03-310001004980pcg:TowerLicensesMember2021-12-310001004980pcg:SFGOSaleMember2022-03-310001004980pcg:SFGOSaleMember2021-12-310001004980us-gaap:OtherRegulatoryAssetsLiabilitiesMember2022-03-310001004980us-gaap:OtherRegulatoryAssetsLiabilitiesMember2021-12-310001004980pcg:FederalEnergyRegulatoryCommissionMember2022-01-012022-03-310001004980pcg:CaliforniaPublicUtilitiesCommissionMember2022-01-012022-03-310001004980pcg:DistributionRevenueAdjustmentMechanismMemberpcg:RegulatoryBalancingAccountsReceivableMember2022-03-310001004980pcg:DistributionRevenueAdjustmentMechanismMemberpcg:RegulatoryBalancingAccountsReceivableMember2021-12-310001004980pcg:EnergyProcurementCostsMemberpcg:RegulatoryBalancingAccountsReceivableMember2022-03-310001004980pcg:EnergyProcurementCostsMemberpcg:RegulatoryBalancingAccountsReceivableMember2021-12-310001004980pcg:PublicPurposeProgramsMemberpcg:RegulatoryBalancingAccountsReceivableMember2022-03-310001004980pcg:PublicPurposeProgramsMemberpcg:RegulatoryBalancingAccountsReceivableMember2021-12-310001004980pcg:FireHazardPreventionMemorandumAccountMemberpcg:RegulatoryBalancingAccountsReceivableMember2022-03-310001004980pcg:FireHazardPreventionMemorandumAccountMemberpcg:RegulatoryBalancingAccountsReceivableMember2021-12-310001004980pcg:FireRiskMitigationMemorandumAccountMemberpcg:RegulatoryBalancingAccountsReceivableMember2022-03-310001004980pcg:FireRiskMitigationMemorandumAccountMemberpcg:RegulatoryBalancingAccountsReceivableMember2021-12-310001004980pcg:WildFireMitigationPlanMemorandumAccountMemberpcg:RegulatoryBalancingAccountsReceivableMember2022-03-310001004980pcg:WildFireMitigationPlanMemorandumAccountMemberpcg:RegulatoryBalancingAccountsReceivableMember2021-12-310001004980pcg:RegulatoryBalancingAccountsReceivableMemberpcg:WildfireMitigationBalancingAccountMember2022-03-310001004980pcg:RegulatoryBalancingAccountsReceivableMemberpcg:WildfireMitigationBalancingAccountMember2021-12-310001004980pcg:GeneralRateCaseMemorandumAccountsMemberpcg:RegulatoryBalancingAccountsReceivableMember2022-03-310001004980pcg:GeneralRateCaseMemorandumAccountsMemberpcg:RegulatoryBalancingAccountsReceivableMember2021-12-310001004980pcg:RegulatoryBalancingAccountsReceivableMemberpcg:VegetationManagementBalancingAccountMember2022-03-310001004980pcg:RegulatoryBalancingAccountsReceivableMemberpcg:VegetationManagementBalancingAccountMember2021-12-310001004980pcg:RegulatoryBalancingAccountsReceivableMemberpcg:RiskTransferBalancingAccountMember2022-03-310001004980pcg:RegulatoryBalancingAccountsReceivableMemberpcg:RiskTransferBalancingAccountMember2021-12-310001004980pcg:RegulatoryBalancingAccountsReceivableMemberpcg:WildfireExpenseMemorandumAccountMember2022-03-310001004980pcg:RegulatoryBalancingAccountsReceivableMemberpcg:WildfireExpenseMemorandumAccountMember2021-12-310001004980pcg:RegulatoryBalancingAccountsReceivableMemberpcg:ResidentialUncollectiblesBalancingAccountsMember2021-12-310001004980pcg:RegulatoryBalancingAccountsReceivableMemberpcg:CatastrophicEventMemorandumAccountMember2022-03-310001004980pcg:RegulatoryBalancingAccountsReceivableMemberpcg:CatastrophicEventMemorandumAccountMember2021-12-310001004980pcg:OtherCurrentBalancingAccountsMemberpcg:RegulatoryBalancingAccountsReceivableMember2022-03-310001004980pcg:OtherCurrentBalancingAccountsMemberpcg:RegulatoryBalancingAccountsReceivableMember2021-12-310001004980pcg:RegulatoryBalancingAccountsReceivableMember2022-03-310001004980pcg:RegulatoryBalancingAccountsReceivableMember2021-12-310001004980pcg:RegulatoryBalancingAccountsPayableMemberpcg:DistributionRevenueAdjustmentMechanismMember2022-03-310001004980pcg:RegulatoryBalancingAccountsPayableMemberpcg:DistributionRevenueAdjustmentMechanismMember2021-12-310001004980pcg:RegulatoryBalancingAccountsPayableMemberus-gaap:ElectricTransmissionMember2022-03-310001004980pcg:RegulatoryBalancingAccountsPayableMemberus-gaap:ElectricTransmissionMember2021-12-310001004980pcg:RegulatoryBalancingAccountsPayableMemberpcg:GasDistributionAndTransmissionMember2022-03-310001004980pcg:RegulatoryBalancingAccountsPayableMemberpcg:GasDistributionAndTransmissionMember2021-12-310001004980pcg:RegulatoryBalancingAccountsPayableMemberpcg:EnergyProcurementCostsMember2022-03-310001004980pcg:RegulatoryBalancingAccountsPayableMemberpcg:EnergyProcurementCostsMember2021-12-310001004980pcg:PublicPurposeProgramsMemberpcg:RegulatoryBalancingAccountsPayableMember2022-03-310001004980pcg:PublicPurposeProgramsMemberpcg:RegulatoryBalancingAccountsPayableMember2021-12-310001004980pcg:NuclearDecommissioningAdjustmentMechanismMemberpcg:RegulatoryBalancingAccountsPayableMember2022-03-310001004980pcg:NuclearDecommissioningAdjustmentMechanismMemberpcg:RegulatoryBalancingAccountsPayableMember2021-12-310001004980pcg:OtherCurrentBalancingAccountsMemberpcg:RegulatoryBalancingAccountsPayableMember2022-03-310001004980pcg:OtherCurrentBalancingAccountsMemberpcg:RegulatoryBalancingAccountsPayableMember2021-12-310001004980pcg:RegulatoryBalancingAccountsPayableMember2022-03-310001004980pcg:RegulatoryBalancingAccountsPayableMember2021-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:RevolvingCreditFacilityMember2022-03-310001004980us-gaap:RevolvingCreditFacilityMembersrt:ParentCompanyMember2022-03-310001004980us-gaap:RevolvingCreditFacilityMember2022-03-310001004980pcg:PacificGasElectricCoMemberpcg:ReceivablesSecuritizationProgramMemberus-gaap:SubsequentEventMember2022-04-250001004980pcg:PacificGasElectricCoMemberpcg:A2020UtilityTermLoanCreditAgreementMember2022-03-312022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:SubsequentEventMemberpcg:A364Day2022ATrancheLoansMember2022-04-040001004980pcg:PacificGasElectricCoMemberus-gaap:SubsequentEventMemberpcg:A364Day2022ATrancheLoansMember2022-04-042022-04-040001004980pcg:PacificGasElectricCoMemberus-gaap:SubsequentEventMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMemberpcg:A364Day2022ATrancheLoansMember2022-04-042022-04-040001004980pcg:PacificGasElectricCoMemberus-gaap:SubsequentEventMemberus-gaap:BaseRateMemberpcg:A364Day2022ATrancheLoansMember2022-04-042022-04-040001004980pcg:PacificGasElectricCoMemberus-gaap:SubsequentEventMemberpcg:A364Day2022BTrancheLoansMember2022-04-200001004980pcg:PacificGasElectricCoMemberpcg:A2Year2022BTrancheLoansMemberus-gaap:SubsequentEventMember2022-04-200001004980pcg:PacificGasElectricCoMemberpcg:A2Year2022BTrancheLoansMemberus-gaap:SubsequentEventMember2022-04-202022-04-200001004980pcg:PacificGasElectricCoMemberus-gaap:SubsequentEventMemberpcg:A364Day2022BTrancheLoansMember2022-04-202022-04-200001004980pcg:PacificGasElectricCoMemberpcg:A2Year2022BTrancheLoansMemberus-gaap:SubsequentEventMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2022-04-202022-04-200001004980pcg:PacificGasElectricCoMemberus-gaap:SubsequentEventMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMemberpcg:A364Day2022BTrancheLoansMember2022-04-202022-04-200001004980pcg:PacificGasElectricCoMemberus-gaap:SubsequentEventMemberpcg:A364Day2022BTrancheLoansMemberus-gaap:BaseRateMember2022-04-202022-04-200001004980pcg:PacificGasElectricCoMemberpcg:A2Year2022BTrancheLoansMemberus-gaap:SubsequentEventMemberus-gaap:BaseRateMember2022-04-202022-04-200001004980pcg:NothernCaliforniaWildFireMember2020-04-300001004980pcg:NothernCaliforniaWildFireMember2021-04-230001004980pcg:NothernCaliforniaWildFireMember2021-05-1100010049802022-02-280001004980pcg:PacificGasElectricCoMemberpcg:FirstMortgageBondsStatedMaturity2024Member2022-02-180001004980pcg:PacificGasElectricCoMemberpcg:FirstMortgageBondsStatedMaturity2029Member2022-02-180001004980pcg:FirstMortgageBondsStatedMaturity2032Memberpcg:PacificGasElectricCoMember2022-02-180001004980pcg:PacificGasElectricCoMemberpcg:FirstMortgageBondsStatedMaturity2052Member2022-02-1800010049802022-02-182022-02-180001004980pcg:AtTheMarketEquityDistributionProgramMembersrt:ParentCompanyMemberus-gaap:CommonStockMember2021-04-300001004980pcg:AtTheMarketEquityDistributionProgramMembersrt:ParentCompanyMemberus-gaap:CommonStockMember2022-03-310001004980srt:MinimumMembersrt:ParentCompanyMember2022-03-310001004980srt:MinimumMembersrt:ParentCompanyMember2021-07-080001004980us-gaap:SubsequentEventMember2022-04-210001004980us-gaap:SubsequentEventMembersrt:ParentCompanyMember2022-04-210001004980us-gaap:SubsequentEventMembersrt:MinimumMembersrt:ParentCompanyMember2022-04-210001004980pcg:FireVictimTrustMember2022-01-312022-01-310001004980pcg:FireVictimTrustMemberus-gaap:SubsequentEventMember2022-04-142022-04-140001004980pcg:FireVictimTrustMember2022-01-012022-03-310001004980pcg:FireVictimTrustMemberus-gaap:SubsequentEventMember2022-01-012022-04-2100010049802022-01-3100010049802022-02-082022-02-080001004980pcg:ForwardsFuturesSwapsMemberpcg:NaturalGasMember2022-03-31utr:MMBTU0001004980pcg:ForwardsFuturesSwapsMemberpcg:NaturalGasMember2021-12-310001004980pcg:NaturalGasMemberus-gaap:OptionMember2022-03-310001004980pcg:NaturalGasMemberus-gaap:OptionMember2021-12-310001004980us-gaap:ElectricityMemberpcg:ForwardsFuturesSwapsMember2022-03-31utr:MWh0001004980us-gaap:ElectricityMemberpcg:ForwardsFuturesSwapsMember2021-12-310001004980us-gaap:ElectricityMemberus-gaap:OptionMember2022-03-310001004980us-gaap:ElectricityMemberus-gaap:OptionMember2021-12-310001004980us-gaap:ElectricityMemberpcg:CongestedRevenueRightsMember2022-03-310001004980us-gaap:ElectricityMemberpcg:CongestedRevenueRightsMember2021-12-310001004980pcg:PacificGasElectricCoMemberpcg:CurrentAssetsMemberus-gaap:CommodityContractMember2022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:OtherNoncurrentAssetsMemberus-gaap:CommodityContractMember2022-03-310001004980pcg:PacificGasElectricCoMemberpcg:CurrentLiabilitiesMemberus-gaap:CommodityContractMember2022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:OtherNoncurrentLiabilitiesMemberus-gaap:CommodityContractMember2022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:CommodityContractMember2022-03-310001004980pcg:PacificGasElectricCoMemberpcg:CurrentAssetsMemberus-gaap:CommodityContractMember2021-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:OtherNoncurrentAssetsMemberus-gaap:CommodityContractMember2021-12-310001004980pcg:PacificGasElectricCoMemberpcg:CurrentLiabilitiesMemberus-gaap:CommodityContractMember2021-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:OtherNoncurrentLiabilitiesMemberus-gaap:CommodityContractMember2021-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:CommodityContractMember2021-12-310001004980us-gaap:FairValueInputsLevel1Member2022-03-310001004980us-gaap:FairValueInputsLevel2Member2022-03-310001004980us-gaap:FairValueInputsLevel3Member2022-03-310001004980us-gaap:FairValueInputsLevel1Memberpcg:NuclearDecommissioningTrustMember2022-03-310001004980us-gaap:FairValueInputsLevel2Memberpcg:NuclearDecommissioningTrustMember2022-03-310001004980us-gaap:FairValueInputsLevel3Memberpcg:NuclearDecommissioningTrustMember2022-03-310001004980pcg:NuclearDecommissioningTrustMember2022-03-310001004980pcg:NuclearDecommissioningTrustMemberus-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2022-03-310001004980us-gaap:FairValueInputsLevel1Memberpcg:PriceRiskDerivativeElectricityMember2022-03-310001004980us-gaap:FairValueInputsLevel2Memberpcg:PriceRiskDerivativeElectricityMember2022-03-310001004980us-gaap:FairValueInputsLevel3Memberpcg:PriceRiskDerivativeElectricityMember2022-03-310001004980pcg:PriceRiskDerivativeElectricityMember2022-03-310001004980us-gaap:FairValueInputsLevel1Memberpcg:PriceRiskDerivativeGasMember2022-03-310001004980us-gaap:FairValueInputsLevel2Memberpcg:PriceRiskDerivativeGasMember2022-03-310001004980us-gaap:FairValueInputsLevel3Memberpcg:PriceRiskDerivativeGasMember2022-03-310001004980pcg:PriceRiskDerivativeGasMember2022-03-310001004980us-gaap:FairValueInputsLevel1Memberpcg:RabbiTrustsMember2022-03-310001004980pcg:RabbiTrustsMemberus-gaap:FairValueInputsLevel2Member2022-03-310001004980pcg:RabbiTrustsMemberus-gaap:FairValueInputsLevel3Member2022-03-310001004980pcg:RabbiTrustsMember2022-03-310001004980us-gaap:FairValueInputsLevel1Memberpcg:LongTermDisabilityTrustMember2022-03-310001004980us-gaap:FairValueInputsLevel2Memberpcg:LongTermDisabilityTrustMember2022-03-310001004980us-gaap:FairValueInputsLevel3Memberpcg:LongTermDisabilityTrustMember2022-03-310001004980pcg:LongTermDisabilityTrustMember2022-03-310001004980us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberpcg:LongTermDisabilityTrustMember2022-03-310001004980us-gaap:FairValueInputsLevel1Member2021-12-310001004980us-gaap:FairValueInputsLevel2Member2021-12-310001004980us-gaap:FairValueInputsLevel3Member2021-12-310001004980us-gaap:FairValueInputsLevel1Memberpcg:NuclearDecommissioningTrustMember2021-12-310001004980us-gaap:FairValueInputsLevel2Memberpcg:NuclearDecommissioningTrustMember2021-12-310001004980us-gaap:FairValueInputsLevel3Memberpcg:NuclearDecommissioningTrustMember2021-12-310001004980pcg:NuclearDecommissioningTrustMember2021-12-310001004980pcg:NuclearDecommissioningTrustMemberus-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2021-12-310001004980us-gaap:FairValueInputsLevel1Memberpcg:PriceRiskDerivativeElectricityMember2021-12-310001004980us-gaap:FairValueInputsLevel2Memberpcg:PriceRiskDerivativeElectricityMember2021-12-310001004980us-gaap:FairValueInputsLevel3Memberpcg:PriceRiskDerivativeElectricityMember2021-12-310001004980pcg:PriceRiskDerivativeElectricityMember2021-12-310001004980us-gaap:FairValueInputsLevel1Memberpcg:PriceRiskDerivativeGasMember2021-12-310001004980us-gaap:FairValueInputsLevel2Memberpcg:PriceRiskDerivativeGasMember2021-12-310001004980us-gaap:FairValueInputsLevel3Memberpcg:PriceRiskDerivativeGasMember2021-12-310001004980pcg:PriceRiskDerivativeGasMember2021-12-310001004980us-gaap:FairValueInputsLevel1Memberpcg:RabbiTrustsMember2021-12-310001004980pcg:RabbiTrustsMemberus-gaap:FairValueInputsLevel2Member2021-12-310001004980pcg:RabbiTrustsMemberus-gaap:FairValueInputsLevel3Member2021-12-310001004980pcg:RabbiTrustsMember2021-12-310001004980us-gaap:FairValueInputsLevel1Memberpcg:LongTermDisabilityTrustMember2021-12-310001004980us-gaap:FairValueInputsLevel2Memberpcg:LongTermDisabilityTrustMember2021-12-310001004980us-gaap:FairValueInputsLevel3Memberpcg:LongTermDisabilityTrustMember2021-12-310001004980pcg:LongTermDisabilityTrustMember2021-12-310001004980us-gaap:FairValueMeasuredAtNetAssetValuePerShareMemberpcg:LongTermDisabilityTrustMember2021-12-310001004980pcg:CongestedRevenueRightsMemberus-gaap:MarketApproachValuationTechniqueMember2022-03-310001004980pcg:CongestedRevenueRightsMemberus-gaap:MeasurementInputCommodityMarketPriceMembersrt:MinimumMemberus-gaap:MarketApproachValuationTechniqueMember2022-03-310001004980pcg:CongestedRevenueRightsMemberus-gaap:MeasurementInputCommodityMarketPriceMembersrt:MaximumMemberus-gaap:MarketApproachValuationTechniqueMember2022-03-310001004980pcg:CongestedRevenueRightsMemberus-gaap:MeasurementInputCommodityMarketPriceMembersrt:WeightedAverageMemberus-gaap:MarketApproachValuationTechniqueMember2022-03-310001004980pcg:PowerPurchaseAgreementsMemberus-gaap:ValuationTechniqueDiscountedCashFlowMember2022-03-310001004980pcg:PowerPurchaseAgreementsMembersrt:MinimumMemberus-gaap:ValuationTechniqueDiscountedCashFlowMemberus-gaap:MeasurementInputCommodityForwardPriceMember2022-03-310001004980pcg:PowerPurchaseAgreementsMembersrt:MaximumMemberus-gaap:ValuationTechniqueDiscountedCashFlowMemberus-gaap:MeasurementInputCommodityForwardPriceMember2022-03-310001004980pcg:PowerPurchaseAgreementsMembersrt:WeightedAverageMemberus-gaap:ValuationTechniqueDiscountedCashFlowMemberus-gaap:MeasurementInputCommodityForwardPriceMember2022-03-310001004980pcg:CongestedRevenueRightsMemberus-gaap:MarketApproachValuationTechniqueMember2021-12-310001004980pcg:CongestedRevenueRightsMemberus-gaap:MeasurementInputCommodityMarketPriceMembersrt:MinimumMemberus-gaap:MarketApproachValuationTechniqueMember2021-12-310001004980pcg:CongestedRevenueRightsMemberus-gaap:MeasurementInputCommodityMarketPriceMembersrt:MaximumMemberus-gaap:MarketApproachValuationTechniqueMember2021-12-310001004980pcg:CongestedRevenueRightsMemberus-gaap:MeasurementInputCommodityMarketPriceMembersrt:WeightedAverageMemberus-gaap:MarketApproachValuationTechniqueMember2021-12-310001004980pcg:PowerPurchaseAgreementsMemberus-gaap:ValuationTechniqueDiscountedCashFlowMember2021-12-310001004980pcg:PowerPurchaseAgreementsMembersrt:MinimumMemberus-gaap:ValuationTechniqueDiscountedCashFlowMemberus-gaap:MeasurementInputCommodityForwardPriceMember2021-12-310001004980pcg:PowerPurchaseAgreementsMembersrt:MaximumMemberus-gaap:ValuationTechniqueDiscountedCashFlowMemberus-gaap:MeasurementInputCommodityForwardPriceMember2021-12-310001004980pcg:PowerPurchaseAgreementsMembersrt:WeightedAverageMemberus-gaap:ValuationTechniqueDiscountedCashFlowMemberus-gaap:MeasurementInputCommodityForwardPriceMember2021-12-310001004980us-gaap:FairValueInputsLevel3Memberpcg:PriceRiskManagementInstrumentsMember2021-12-310001004980us-gaap:FairValueInputsLevel3Memberpcg:PriceRiskManagementInstrumentsMember2020-12-310001004980us-gaap:FairValueInputsLevel3Memberpcg:PriceRiskManagementInstrumentsMember2022-01-012022-03-310001004980us-gaap:FairValueInputsLevel3Memberpcg:PriceRiskManagementInstrumentsMember2021-01-012021-03-310001004980us-gaap:FairValueInputsLevel3Memberpcg:PriceRiskManagementInstrumentsMember2022-03-310001004980us-gaap:FairValueInputsLevel3Memberpcg:PriceRiskManagementInstrumentsMember2021-03-310001004980us-gaap:CarryingReportedAmountFairValueDisclosureMember2022-03-310001004980us-gaap:FairValueInputsLevel2Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2022-03-310001004980us-gaap:CarryingReportedAmountFairValueDisclosureMember2021-12-310001004980us-gaap:FairValueInputsLevel2Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2021-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:CarryingReportedAmountFairValueDisclosureMember2022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:FairValueInputsLevel2Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:CarryingReportedAmountFairValueDisclosureMember2021-12-310001004980pcg:PacificGasElectricCoMemberus-gaap:FairValueInputsLevel2Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2021-12-310001004980pcg:MoneyMarketInvestmentsMember2022-03-310001004980pcg:GlobalEquitySecuritiesMember2022-03-310001004980us-gaap:FixedIncomeSecuritiesMember2022-03-310001004980pcg:MoneyMarketInvestmentsMember2021-12-310001004980pcg:GlobalEquitySecuritiesMember2021-12-310001004980us-gaap:FixedIncomeSecuritiesMember2021-12-310001004980pcg:KincadeFire2019Member2019-10-23utr:acrepcg:numberOfFatalitypcg:injurypcg:structure0001004980pcg:KincadeFire2019Member2019-10-232019-11-04pcg:numberOfPeople0001004980pcg:PacificGasElectricCoMemberpcg:KincadeFire2019Memberpcg:SonomaContryDistrictAttorneyMember2021-04-06pcg:felonypcg:misdemeanor0001004980pcg:PacificGasElectricCoMemberpcg:KincadeFire2019Member2021-05-11pcg:count0001004980pcg:KincadeFire2019Member2022-01-270001004980pcg:KincadeFire2019Member2022-01-280001004980pcg:KincadeFire2019Memberus-gaap:SubsequentEventMember2022-04-08pcg:position0001004980pcg:KincadeFire2019Member2021-12-02pcg:transmissionLine0001004980pcg:PacificGasElectricCoMemberpcg:KincadeFire2019Member2022-03-310001004980pcg:PacificGasElectricCoMemberpcg:KincadeFire2019Member2022-01-012022-03-310001004980pcg:KincadeFire2019Memberus-gaap:SubsequentEventMember2022-04-21pcg:complaintpcg:plaintiff0001004980pcg:KincadeFire2019Member2022-01-052022-01-050001004980pcg:KincadeFire2019Member2021-01-012021-12-310001004980pcg:KincadeFire2019Member2021-12-310001004980pcg:KincadeFire2019Member2022-01-012022-03-310001004980pcg:KincadeFire2019Member2022-03-310001004980pcg:ZoggFire2020Member2020-09-27pcg:fatality0001004980pcg:ZoggComplaint2020Member2021-09-240001004980pcg:ZoggFire2020Member2021-11-180001004980us-gaap:SubsequentEventMemberpcg:ZoggFire2020Member2022-04-21pcg:numberOfPlaintiff0001004980pcg:ZoggFire2020Member2022-03-182022-03-180001004980pcg:ZoggFire2020Member2022-01-012022-03-310001004980pcg:ZoggFire2020Member2021-12-310001004980pcg:ZoggFire2020Member2022-03-310001004980pcg:InsuranceCoverageForWildfireEventsMember2021-08-310001004980pcg:DixieFire2021Member2021-07-130001004980us-gaap:SubsequentEventMemberpcg:DixieFire2021Member2022-04-110001004980us-gaap:SubsequentEventMemberpcg:DixieFire2021Member2022-04-21pcg:numberOfClaimHolder0001004980pcg:DixieFire2021Member2021-01-012021-12-310001004980pcg:DixieFire2021Member2021-10-292021-10-290001004980pcg:NationalParkMemberpcg:DixieFire2021Member2021-10-290001004980pcg:NationalForrestMemberpcg:DixieFire2021Member2021-10-290001004980pcg:ZoggFire2020AndDixieFire2021Member2022-03-310001004980pcg:DixieFire2021Member2022-03-310001004980pcg:AB1054WildfireFundMemberpcg:DixieFire2021Member2022-01-012022-03-310001004980pcg:FERCMemberpcg:DixieFire2021Member2022-01-012022-03-310001004980pcg:WEMAMemberpcg:DixieFire2021Member2022-01-012022-03-310001004980pcg:InsuranceMemberpcg:DixieFire2021Member2022-01-012022-03-310001004980pcg:DixieFire2021Member2022-01-012022-03-310001004980us-gaap:SubsequentEventMemberpcg:InsuranceCoverageForWildfireEventsMember2022-04-280001004980srt:ScenarioForecastMemberpcg:InsuranceCoverageForWildfireEventsMember2022-04-012023-04-010001004980srt:ScenarioForecastMemberpcg:InsuranceCoverageForWildfireEventsMember2022-08-012023-08-010001004980pcg:InsuranceCoverageForWildfireEventsMember2022-03-310001004980us-gaap:SubsequentEventMemberpcg:InsuranceCoverageForNonWildfireLiabilitiesMember2022-04-280001004980us-gaap:SubsequentEventMemberpcg:InsuranceCoverageForNonWildfireLiabilitiesMember2022-04-012022-04-280001004980pcg:InsuranceCoverageForNonWildfireLiabilitiesMember2022-03-310001004980pcg:DixieFire2021Member2021-12-310001004980us-gaap:SubsequentEventMemberpcg:ZoggFire2020Member2022-04-202022-04-2000010049802019-08-232019-08-230001004980pcg:DerivativeLawsuitsFiledInTheSanFranciscoCountySuperiorCourtMemberpcg:BreachOfFiduciaryDutiesMember2017-11-20pcg:lawsuit0001004980pcg:BreachOfFiduciaryDutiesMember2021-02-24pcg:claim0001004980us-gaap:SubsequentEventMemberpcg:BreachOfFiduciaryDutiesMember2022-04-050001004980pcg:WildfireRelatedClassActionMember2018-06-300001004980pcg:WildfireRelatedClassActionMember2019-02-220001004980pcg:WildfireRelatedClassActionMember2022-03-310001004980pcg:ComplaintsBroughtByButteCountyDistrictAttorneyMemberus-gaap:LossFromCatastrophesMemberpcg:PacificGasElectricCoMember2020-03-170001004980pcg:TransmissionOwnerRateCaseRevenueMember2022-03-310001004980pcg:PacificGasElectricCoMemberus-gaap:ElectricityMember2018-09-212018-09-210001004980pcg:PacificGasElectricCoMemberus-gaap:ElectricityMember2022-03-172022-03-170001004980pcg:PacificGasElectricCoMember2017-03-012022-03-310001004980pcg:CEMAInterimRateReliefMemberpcg:CatastrophicEventPeriodOneMember2018-03-30pcg:catastrophicEvent0001004980pcg:CEMAInterimRateReliefMemberpcg:CatastrophicEventPeriodTwoMember2018-03-300001004980pcg:CEMAInterimRateReliefMember2019-04-2500010049802021-09-300001004980pcg:ExtraordinaryCircumstancesMember2022-03-310001004980pcg:NotExtraordinaryCircumstancesMember2022-03-310001004980pcg:DisallowanceOfPlantCostsMember2016-06-232016-06-230001004980pcg:LossContingencyNaturePeriodOneMemberpcg:DisallowanceOfPlantCostsMember2020-07-310001004980pcg:DisallowanceOfPlantCostsMember2020-07-310001004980pcg:LossContingencyNaturePeriodOneMemberpcg:DisallowanceOfPlantCostsMember2021-07-070001004980pcg:LossContingencyNaturePeriodTwoMemberpcg:DisallowanceOfPlantCostsMember2021-07-070001004980pcg:LossContingencyNaturePeriodTwoMemberpcg:DisallowanceOfPlantCostsMember2021-07-072021-07-070001004980pcg:LossContingencyNaturePeriodThreeMemberpcg:DisallowanceOfPlantCostsMember2021-07-070001004980pcg:LossContingencyNaturePeriodThreeMemberpcg:DisallowanceOfPlantCostsMember2021-07-072021-07-070001004980pcg:PacificGasElectricCoMemberpcg:PSPSClassActionMemberus-gaap:PendingLitigationMember2019-12-192019-12-190001004980pcg:TopockSiteMember2022-03-310001004980pcg:PacificGasElectricCoMemberpcg:TopockSiteMember2022-03-310001004980pcg:HinkleyNaturalGasCompressorStationMember2022-03-310001004980pcg:FormerManufacturedGasPlantMember2022-03-310001004980pcg:PacificGasElectricCoMemberpcg:FormerManufacturedGasPlantMember2022-03-310001004980pcg:UtilityOwnedGenerationFacilitiesAndThirdPartyDisposalSitesMember2022-03-310001004980pcg:PacificGasElectricCoMemberpcg:UtilityOwnedGenerationFacilitiesAndThirdPartyDisposalSitesMember2022-03-310001004980pcg:FossilFuelFiredGenerationMember2022-03-31pcg:nuclear_generating_unit0001004980pcg:NuclearIncidentMember2022-03-310001004980pcg:NonNuclearIncidentMember2022-03-310001004980pcg:HumboldtBayUnitMember2022-03-310001004980pcg:NuclearElectricInsuranceLimitedAndEuropeanMutualAssociationForNuclearInsuranceMember2022-03-310001004980pcg:EuropeanMutualAssociationForNuclearInsuranceMember2022-01-012022-03-310001004980pcg:NuclearElectricInsuranceLimitedMember2022-01-012022-03-3100010049802020-10-23utr:sqft


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C., 20549
FORM10-Q
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period endedMarch 31, 2022
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
Registrant
as Specified
in its Charter
State or Other
Jurisdiction of
Incorporation
IRS Employer
Identification
Number
1-12609PG&E CorporationCalifornia94-3234914
1-2348Pacific Gas and Electric CompanyCalifornia94-0742640
PG&E CorporationPacific Gas and Electric Company
77 Beale Street77 Beale Street
P.O. Box 770000P.O. Box 770000
San Francisco,California94177San Francisco, California 94177
Address of principal executive offices, including zip code
PG&E CorporationPacific Gas and Electric Company
415973-1000415973-7000
Registrant’s telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common stock, no par valuePCGThe New York Stock Exchange
Equity UnitsPCGUThe New York Stock Exchange
First preferred stock, cumulative, par value $25 per share, 5% series A redeemablePCG-PENYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% redeemablePCG-PDNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.80% redeemablePCG-PGNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.50% redeemablePCG-PHNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemablePCG-PINYSE American LLC
First preferred stock, cumulative, par value $25 per share, 6% nonredeemablePCG-PANYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemablePCG-PBNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% nonredeemablePCG-PCNYSE American LLC
1


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. 
PG&E Corporation:YesNo
Pacific Gas and Electric Company:YesNo
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).
PG&E Corporation:YesNo
Pacific Gas and Electric Company:YesNo
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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.
PG&E Corporation:Large accelerated filer
Accelerated filer
 
Non-accelerated filer  
 Smaller reporting companyEmerging growth company
Pacific Gas and Electric Company:Large accelerated filer
Accelerated filer
 
Non-accelerated filer
 Smaller reporting companyEmerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
PG&E Corporation:
Pacific 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).
PG&E Corporation:Yes
No
Pacific Gas and Electric Company:Yes
No
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
PG&E Corporation:
YesNo
Pacific Gas and Electric Company:
YesNo
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Common stock outstanding as of April 21, 2022: 
PG&E Corporation:
2,465,220,279*
Pacific Gas and Electric Company:
264,374,809
*Includes 377,743,590 shares of common stock held by PG&E ShareCo LLC, a wholly-owned subsidiary of PG&E Corporation, and 100,000,000 shares of common stock held by Pacific Gas and Electric Company.


2


PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2022
TABLE OF CONTENTS
SEC Form 10-Q Reference Number
3


4


GLOSSARY
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
2021 Form 10-KPG&E Corporation’s and Pacific Gas and Electric Company’s combined Annual Report on
Form 10-K for the year ended December 31, 2021
ABAssembly Bill
Amended ArticlesAmended and Restated Articles of Incorporation of PG&E Corporation and the Utility, each filed on June 22, 2020
AROasset retirement obligation
ASUaccounting standard update issued by the FASB
Bankruptcy Codethe United States Bankruptcy Code
Bankruptcy Courtthe U.S. Bankruptcy Court for the Northern District of California
CAISOCalifornia Independent System Operator Corporation
Cal FireCalifornia Department of Forestry and Fire Protection
CAPPCalifornia Arrearage Payment Program
CARECalifornia Alternate Rates for Energy Program
CCACommunity Choice Aggregator
CEMACatastrophic Event Memorandum Account
Chapter 11Chapter 11 of Title 11 of the U.S. Code
Chapter 11 Casesthe voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
Confirmation Orderthe order confirming the Plan, dated as of June 20, 2020 with the Bankruptcy Court
CHTCustomer Harm Threshold
CPPMACOVID-19 Pandemic Protections Memorandum Account
CPUCCalifornia Public Utilities Commission
CRRscongestion revenue rights
DADirect Access
Diablo CanyonDiablo Canyon nuclear power plant
District CourtUnited States District Court for the Northern District of California
DTAdeferred tax asset
DTSCDepartment of Toxic Substances Control
EMANIEuropean Mutual Association for Nuclear Insurance
Emergence Date
July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
EOExecutive Order
EOEPEnhanced Oversight and Enforcement Process
EPSearnings per common share
EPSS
Enhanced Powerline Safety Settings
EVMenhanced vegetation management
Exchange ActSecurities Exchange Act of 1934
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FHPMAFire Hazard Prevention Memorandum Account
Fire Victim TrustThe trust established pursuant to the Plan for the benefit of holders of the Fire Victim Claims into which the Aggregate Fire Victim Consideration (as defined in the Plan) has been, and will continue to be funded
FRMMAFire Risk Mitigation Memorandum Account
GAAPU.S. Generally Accepted Accounting Principles
GOgeneral order
GRCgeneral rate case
GT&Sgas transmission and storage
5


HSMhazardous substance memorandum account
IRCInternal Revenue Code
IOUsinvestor-owned utility(ies)
Kincade Amended ComplaintThe amended criminal complaint filed by the Sonoma County District Attorney’s Office on January 28, 2022 in connection with the 2019 Kincade fire
Kincade ComplaintThe criminal complaint filed by the Sonoma County District Attorney’s Office on April 6, 2021 in connection with the 2019 Kincade fire
Lakeside Building300 Lakeside Drive, Oakland, California, 94612
LSELoad-serving entity
MD&AManagement’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part I, Item 2, of this Form 10-Q
MGMAMicrogrids Memorandum Account
MGPmanufactured gas plants
NAVnet asset value
NEILNuclear Electric Insurance Limited
NEMnet energy metering
New SharesShares of PG&E Corporation common stock held by ShareCo that may be exchanged for Plan Shares
as contemplated by the Share Exchange and Tax Matters Agreement
NRCNuclear Regulatory Commission
OEISOffice of Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)
OIIorder instituting investigation
OIRorder instituting rulemaking
PDproposed decision
PERAPublic Employees Retirement Association
Plan
PG&E Corporation and the Utility, Knighthead Capital Management, LLC, and Abrams Capital Management, LP Joint Chapter 11 Plan of Reorganization, dated as of June 19, 2020
Plan SharesShares of PG&E Corporation common stock issued to the Fire Victim Trust pursuant to the Plan
PSPSPublic Safety Power Shutoff
RAResource Adequacy
Receivables Securitization ProgramThe accounts receivable securitization program entered into by the Utility on October 5, 2020, providing for the sale of a portion of the Utility's accounts receivable and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions
ROEreturn on equity
ROU assetright-of-use asset
RTBARisk Transfer Balancing Account
RUBAResidential Uncollectibles Balancing Account
SBSenate Bill
SECU.S. Securities and Exchange Commission
SEDSafety and Enforcement Division of the CPUC
SFGOThe Utility’s San Francisco General Office headquarters complex
Share Exchange and
Tax Matters Agreement
Share Exchange and Tax Matters Agreement dated July 8, 2021 between PG&E Corporation, the
Utility, ShareCo and the Fire Victim Trust
ShareCoPG&E ShareCo LLC, a limited liability company whose sole member is PG&E Corporation
SOFRSecured Overnight Financing Rate
SPV
PG&E AR Facility, LLC
Tax ActTax Cuts and Jobs Act of 2017
TOtransmission owner
TURNThe Utility Reform Network
6


UtilityPacific Gas and Electric Company
VIE(s)variable interest entity(ies)
VMBAVegetation Management Balancing Account
WEMAWildfire Expense Memorandum Account
Wildfire Fundstatewide fund established by AB 1054 that will be available for eligible electric utility
companies to pay eligible claims for liabilities arising from wildfires occurring after July 12,
2019 that are caused by the applicable electric utility company’s equipment
WMBAWildfire Mitigation Balancing Account
WMCEWildfire Mitigation and Catastrophic Events
WMPwildfire mitigation plan
WMPMAWildfire Mitigation Plan Memorandum Account
Zogg Complaint
The criminal complaint filed by the Shasta County District Attorney’s Office on September 24, 2021

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines, associated with various investigations and proceedings; forecasts of capital expenditures; forecasts of expense reduction; estimates and assumptions used in critical accounting estimates, including those relating to insurance receivables, regulatory assets and liabilities, environmental remediation, litigation, third-party claims, the Wildfire Fund, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “potential” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

the extent to which the Wildfire Fund and revised recoverability standard under AB 1054 effectively mitigates the risk of liability for damages arising from catastrophic wildfires, including whether the Utility maintains an approved WMP and a valid safety certification and whether the Wildfire Fund has sufficient remaining funds;

the risks and uncertainties associated with wildfires that have occurred or may occur in the Utility’s service territory, including the wildfire that began on October 23, 2019 northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), the wildfire that began on September 27, 2020 in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), the wildfire that began on July 13, 2021 near the Cresta Dam in the Feather River Canyon in Plumas County, California (the “2021 Dixie fire”), and any other wildfires for which the causes have yet to be determined; the damage caused by such wildfires; the extent of the Utility’s liability in connection with such wildfires (including the risk that the Utility may be found liable for damages regardless of fault); investigations into such wildfires, including those being conducted by the CPUC; the outcome of the criminal proceeding initiated against the Utility in connection with the 2020 Zogg fire and three other fires in Shasta County, California; potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other enforcement agency were to bring an enforcement action in respect of any such fire; the risk that the Utility is not able to recover costs from insurance, from the Wildfire Fund or through rates; and the effect on PG&E Corporation’s and the Utility’s reputations of such wildfires, investigations and proceedings;

the extent to which the Utility’s wildfire mitigation initiatives are effective, including the Utility’s ability to comply with the targets and metrics set forth in its WMP; to retain or contract for the workforce necessary to execute its WMP; the effectiveness of its system hardening, including undergrounding; and the cost of the program and the timing and outcome of any proceeding to recover such costs through rates;

the impact of the Utility’s implementation of its PSPS program, and whether any fines, penalties or civil liability for damages will be imposed on the Utility as a result; the costs in connection with PSPS events, the timing and outcome of any proceeding to recover such costs through rates, and the effects on PG&E Corporation’s and the Utility’s reputations caused by implementation of the PSPS program;

7


the Utility’s ability to safely, reliably, and efficiently construct, maintain, operate, protect, and decommission its facilities, and provide electricity and natural gas services safely and reliably;

the availability, cost, coverage, and terms of the Utility’s insurance, including insurance for wildfire, nuclear, and other liabilities, the timing of any insurance recoveries, and recovery of the costs of such insurance or, in the event liabilities exceed insured amounts, the ability to recover uninsured losses through rates or from other third parties;

significant changes to the electric power and gas industries driven by technological advancements and a decarbonized economy;

cyber or physical attacks, including acts of terrorism, war, and vandalism, on the Utility or its third-party vendors, contractors, or customers (or others with whom they have shared data) which could result in operational disruption; the misappropriation or loss of confidential or proprietary assets, information or data, including customer, employee, financial, or operating system information, or intellectual property; corruption of data; or potential costs, lost revenues, litigation, or reputational harm incurred in connection therewith;

the impact of severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, extreme heat events, drought, earthquakes, lightning, tsunamis, rising sea levels, mudslides, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, and other events that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies, and the effectiveness of the Utility’s efforts to prevent, mitigate, or respond to such conditions or events; the reparation and other costs that the Utility may incur in connection with such conditions or events; the impact of the adequacy of the Utility’s emergency preparedness; whether the Utility incurs liability to third parties for property damage or personal injury caused by such events; whether the Utility is able to procure replacement power; and whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events;

the ability of the Utility to meet the conditions in its corrective action plan and exit the EOEP;

the timing and outcome of future regulation and federal, state or local legislation, their implementation, and their interpretation; the cost to comply with such regulation and legislation; and the extent to which the Utility recovers its associated compliance and investment costs, including those regarding:

wildfires, including inverse condemnation reform, wildfire insurance, and additional wildfire mitigation measures or other reforms targeted at the Utility or its industry;

the environment, including the costs incurred to discharge the Utility’s remediation obligations or the costs to comply with standards for greenhouse gas emissions, renewable energy targets, energy efficiency standards, distributed energy resources, and electric vehicles;

the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, and cooling water intake, and the Utility’s ability to continue operating Diablo Canyon until its planned retirement;

the regulation of utilities and their holding companies, including the conditions imposed on PG&E Corporation when it became the Utility’s holding company and whether the Utility can make distributions to PG&E Corporation; and

taxes and tax audits;

the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested;

8


whether the Utility can control its operating costs within the authorized levels of spending, and timely recover its costs through rates; whether the Utility can continue implementing a streamlined organizational structure and achieve projected savings; the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons;

the outcome of current and future self-reports, investigations or other enforcement actions, or notices of violation that could be issued related to the Utility’s compliance with laws, rules, regulations, or orders applicable to its gas and electric operations; the construction, expansion, or replacement of its electric and gas facilities; electric grid reliability; audit, inspection and maintenance practices; customer billing and privacy; physical and cybersecurity protections; environmental laws and regulations; or otherwise, such as fines, penalties, remediation obligations, the transfer of ownership of the Utility’s assets to municipalities or other public entities, or the implementation of corporate governance, operational or other changes in connection with the EOEP;

the risks and uncertainties associated with PG&E Corporation’s and the Utility’s substantial indebtedness and the limitations on their operating flexibility in the documents governing that indebtedness;

the risks and uncertainties associated with the timing and outcomes of PG&E Corporation’s and the Utility’s ongoing litigation, including appeals of the Confirmation Order; certain indemnity obligations to current and former officers and directors, as well as potential indemnity obligations to underwriters for certain of the Utility’s note offerings; three purported class actions that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509; the debarment proceeding; the purported PSPS class action filed in December 2019; and other third-party claims, including the extent to which related costs can be recovered through insurance, rates, or from other third parties;

the ability of PG&E Corporation and the Utility to securitize (i) the remaining $2.4 billion of fire risk mitigation capital expenditures that were or will be incurred by the Utility and (ii) $7.5 billion of costs related to the multiple wildfires that began on October 8, 2017 and spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”), in a financing transaction that is designed to be rate neutral to customers;

the risks and uncertainties associated with any future substantial sales of shares of common stock of PG&E Corporation by existing shareholders, including the Fire Victim Trust;

whether PG&E Corporation or the Utility undergoes an “ownership change” within the meaning of Section 382 of the IRC, as a result of which tax attributes could be limited;

PG&E Corporation’s and the Utility’s historical financial information not being indicative of future financial performance as a result of the Chapter 11 Cases and the financial and other restructuring undergone by PG&E Corporation and the Utility in connection with their emergence from Chapter 11;

the ultimate amount of unrecoverable environmental costs the Utility incurs associated with the Utility’s natural gas compressor station site located near Hinkley, California and the Utility’s fossil fuel-fired generation sites;

the impact that reductions in Utility customer demand for electricity and natural gas, driven by customer departures to CCAs, DA providers and legislative mandates to replace gas-fuel technologies, have on the Utility’s ability to make and recover its investments through rates and earn its authorized ROE, and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources, and changing customer demand for its natural gas and electric services;

the supply and price of electricity, natural gas, and nuclear fuel; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its electric generation and energy commodity costs through rates, including its renewable energy procurement costs;

the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms;

9


the risks and uncertainties associated with the Utility’s ability to accurately forecast major capital expenditures, weighted average annual rate base and expense reduction associated with implementation of the Lean operating system;

the risks and uncertainties associated with rising rates for the Utility’s customers;

actions by credit rating agencies to downgrade PG&E Corporation’s or the Utility’s credit ratings;

the severity, extent and duration of the global COVID-19 pandemic and its impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, as well as on energy demand in the Utility’s service territory, the ability of the Utility to collect on customer receivables, the ability of the Utility to mitigate these effects, including with spending reductions, the ability of the Utility to recover any losses incurred in connection with the COVID-19 pandemic, and the impact of workforce disruptions caused either by illness of workers and their family members or workforce attrition related to potential new workplace regulations such as vaccine mandates;

whether PG&E Corporation’s and the Utility’s counterparties are available and able to meet their financial and performance obligations with respect to contracts, credit agreements, and financial instruments, which could be affected by disruptions in the global supply chain caused by the COVID-19 pandemic or otherwise; and

the impact of changes in GAAP, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application.

For more information about the significant risks that could affect the outcome of the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors below and a detailed discussion of these matters contained in Item 2. MD&A. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements, are available free of charge on both PG&E Corporation’s website, www.pgecorp.com, and the Utility's website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC. Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “Chapter 11,” “Wildfire and Safety Updates” and “News & Events: Events & Presentations” tabs, respectively, in order to publicly disseminate such information. Specifically, within two hours during business hours or four hours outside of business hours of the determination that an incident is attributable or allegedly attributable to the Utility’s electric facilities and has resulted in property damage estimated to exceed $50,000, a fatality or injury requiring overnight in-patient hospitalization, or significant public or media attention, the Utility is required to submit an electric incident report including information about such incident. The information included in an electric incident report is limited and may not include important information about the facts and circumstances about the incident due to the limited scope of the reporting requirements and timing of the report and is necessarily limited to information to which the Utility has access at the time of the report. Ignitions are also reportable under CPUC Decision 14-02-015 when they involve self-propagating fire of material other than electrical or communication facilities; the fire traveled greater than one linear meter from the ignition point; and the Utility has knowledge that the fire occurred. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on such website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link.


10


PART I. FINANCIAL INFORMATION

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in Item 1. It should also be read in conjunction with the 2021 Form 10-K.

Summary of Changes in Net Income and Earnings per Share

PG&E Corporation’s net income available for common shareholders was $475 million for the three months ended March 31, 2022, compared to $120 million in the same period in 2021. In the three months ended March 31, 2022, revenues increased as authorized through the 2020 GRC and the FERC formula rate.

Key Factors Affecting Financial Results

PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors:

The Uncertainties in Connection with Any Future Wildfires, Wildfire Insurance, and AB 1054. While PG&E Corporation and the Utility cannot predict the occurrence, timing or extent of damages in connection with future wildfires, factors such as environmental conditions (including weather and vegetation conditions) and the efficacy of wildfire risk mitigation initiatives are expected to influence the frequency and severity of future wildfires. To the extent that future wildfires occur in the Utility’s service territory, the Utility may incur costs associated with the investigations of the causes and origins of such fires, even if it is subsequently determined that such fires were not caused by the Utility’s facilities. The financial impact of future wildfires could be mitigated through insurance, the Wildfire Fund or other forms of cost recovery. However, the Utility may not be able to obtain sufficient wildfire insurance coverage at a reasonable cost, or at all, and any such coverage may include limitations that could result in substantial uninsured losses depending on the amount and type of damages resulting from covered events, including coverage limitations applicable to different insurance layers. The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any Wildfire Fund coverage year (“Coverage Year”) that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. In addition, the policy reforms contemplated by AB 1054 are likely to affect the financial impact of future wildfires on PG&E Corporation and the Utility should any such wildfires occur. The Wildfire Fund is available to the Utility to pay eligible claims for liabilities arising from wildfires and serves as an alternative to traditional insurance products, provided that the Utility satisfies the conditions to the Utility’s ongoing participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds. See “Loss Recoveries” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

However, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund were just and reasonable and therefore not subject to reimbursement, and whether the benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs. Finally, even if the Utility satisfies the ongoing eligibility and other requirements set forth in AB 1054, for eligible claims against the Utility arising from wildfires that occurred between July 12, 2019 and the Utility’s emergence from Chapter 11 on July 1, 2020, the availability of the Wildfire Fund to pay such claims would be capped at 40% of the allowed amount of such claims. See “Wildfire Fund under AB 1054” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

The Costs, Effectiveness, and Execution of the Utility’s Wildfire Mitigation Initiatives. In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires, the spread of wildfires should they occur and the impact of PSPS events.

11


PG&E Corporation and the Utility have incurred substantial expenditures in connection with the 2020-2022 WMP. For more information, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1. The Utility expects that its wildfire mitigation initiatives will continue to involve substantial and ongoing expenditures. The extent to which the Utility will be able to recover these expenditures and potential other costs through rates is uncertain.

The Utility has implemented operational changes and investments that reduce wildfire risk, including the EPSS, PSPS, vegetation management, asset inspection, and system hardening programs. These programs, particularly the PSPS and EPSS programs, have been the subject of scrutiny and criticism by various stakeholders, including the California governor, the CPUC, and the court that oversaw the Utility’s probation. The PSPS and EPSS programs have had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators, and policymakers, and future PSPS and EPSS events may increase these negative perceptions.

The Utility is subject to a number of legal and regulatory requirements related to its wildfire mitigation efforts, which require periodic inspections of electric assets and ongoing reporting related to this work. Although the Utility believes that it has complied substantially with these requirements, it is undertaking a review and has identified instances of noncompliance. The Utility intends to update the CPUC and OEIS as its review progresses. The Utility could face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for the late inspections or other noncompliance related to wildfire mitigation efforts. See “Self-Reports to the CPUC” in “Regulatory Matters” below.

While PG&E Corporation and the Utility are committed to taking aggressive wildfire mitigation actions, if additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. The success of the Utility’s wildfire mitigation efforts depends on many factors, including on whether the Utility is able to retain or contract for the workforce necessary to execute its wildfire mitigation actions.

The Timing and Outcome of Ratemaking Proceedings. The Utility’s financial results may be impacted by the timing and outcome of its FERC TO18 rate case and the resulting impact on the TO19 and TO20 rate cases, 2023 GRC, WMCE, and cost of capital applications and its ability to timely recover costs not currently in rates, including costs already incurred and future costs tracked in its CEMA, WEMA, WMPMA, FRMMA, CPPMA, VMBA, WMBA, and RTBA. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the regulatory and political environments, and other factors. See Notes 4 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Regulatory Matters” below.

The Impact of Wildfires. PG&E Corporation’s and the Utility’s liabilities for the 2019 Kincade fire, the 2020 Zogg fire, and the 2021 Dixie fire, are significant and may be excluded from any potential amounts recoverable under applicable insurance policies, the WEMA, FERC TO rates, or the Wildfire Fund under AB 1054. Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have already exceeded potential amounts recoverable under applicable insurance policies. Liabilities in excess of recoverable amounts for these wildfires could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

As of March 31, 2022, PG&E Corporation and the Utility had recorded an aggregate liability of $800 million, $375 million, and $1.15 billion for claims in connection with the 2019 Kincade fire, the 2020 Zogg fire, and the 2021 Dixie fire, respectively, and in each case before available insurance, and, in the case of the 2021 Dixie fire, other probable cost recoveries. These liability amounts correspond to the lower end of the range of reasonably estimable probable losses, but do not include all categories of potential damages and losses. Claims related to the 2019 Kincade fire that were not satisfied in full as of the Emergence Date were not discharged in connection with emerging from Chapter 11.

On September 24, 2021, the Shasta County District Attorney’s Office charged the Utility with 11 felonies and 20 misdemeanors in connection with the 2020 Zogg fire and three other fires in Shasta County, California. If the Utility were to be convicted of certain charges in the Zogg Complaint, the Utility could be subject to material fines, penalties, and restitution, as well as non-monetary remedies such as oversight requirements, and accordingly the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with the 2020 Zogg fire would materially exceed the $375 million of aggregate liability that PG&E Corporation and the Utility have recorded.

12


If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Coverage Year, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, except that recoveries for the 2019 Kincade fire would be subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy, and recoveries for each of these fires would also be subject to the other limitations and requirements under AB 1054. As of March 31, 2022, the Utility had recorded insurance receivables of $430 million for the 2019 Kincade fire, $338 million for the 2020 Zogg fire, and $562 million for the 2021 Dixie fire. The Utility had recorded regulatory recovery and Wildfire Fund receivables of $452 million and $150 million, respectively, for the 2021 Dixie fire. However, there can be no assurance that such amounts will ultimately be recovered, and the Utility does not expect that any of its liability insurance would cover restitution payments ordered by the court presiding over the criminal proceeding in connection with the 2020 Zogg fire. See “2019 Kincade Fire,” “2020 Zogg Fire,” and “2021 Dixie Fire” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information.

The Outcome of Other Enforcement, Litigation, and Regulatory Matters, and Other Government Proposals. The Utility’s financial results may continue to be impacted by the outcome of other current and future enforcement, litigation, and regulatory matters, including those described above as well as the outcome of the Safety Culture OII, and potential penalties in connection with the Utility’s WMP and safety and other self-reports. See Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K. In addition, the Utility’s business profile and financial results could be impacted by the outcome of recent calls for municipalization of part or all of the Utility’s businesses, offers by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions and calls for state intervention, including the possibility of a state takeover of the Utility. PG&E Corporation and the Utility cannot predict the nature, occurrence, timing or extent of any such scenario, and there can be no assurance that any such scenario would not involve significant ownership or management changes to PG&E Corporation or the Utility, including by the state of California.

The Uncertainties in Connection with the Enhanced Oversight and Enforcement Process. On April 15, 2021, the CPUC placed the Utility in step 1 of the EOEP. As a result, the Utility is subject to additional reporting requirements, monitoring, and oversight by the CPUC. See “Enhanced Oversight and Enforcement Process” in “Enforcement and Litigation Matters” below.

The Impact of the COVID-19 Pandemic. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic. The principal areas of near-term impact include liquidity, financial results and business operations, stemming primarily from the ongoing economic hardship of the Utility’s customers and the moratorium on service disconnections. The Utility continues to monitor the overall impact of the COVID-19 pandemic; however, the Utility expects a significant impact on monthly cash collections as long as current circumstances persist. PG&E Corporation and the Utility expect additional financial impacts in the future as a result of COVID-19 pandemic. Other impacts of the COVID-19 pandemic on PG&E Corporation and the Utility have included operational disruptions, workforce disruptions, both in personnel availability (including a reduction in contract labor resources) and deployment, delays in production and shipping of materials used in the Utility’s operations, higher credit spreads and borrowing costs and could potentially also include a reduction in revenue due to the cost of capital adjustment mechanism and incremental financing needs. For more information on the impact of COVID-19 pandemic on PG&E Corporation and the Utility, see “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic.” in Item 1A. Risk Factors in the 2021 Form 10-K and “COVID-19” in Liquidity and Financial Resources below.

For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see Item 1A. Risk Factors in this quarterly report on Form 10-Q and the 2021 Form 10-K.  In addition, this quarterly report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report.  See “Forward-Looking Statements” above for a list of some of the factors that may cause actual results to differ materially.  PG&E Corporation and the Utility are unable to predict all the factors that may affect future results and do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

13


Tax Matters

PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $21.1 billion and California net operating loss carryforward of $18.9 billion as of December 31, 2021.

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the “Ownership Restrictions”). As discussed below under “Update on Ownership Restrictions in PG&E Corporation’s Amended Articles,” due to the election to treat the Fire Victim Trust as a grantor trust for income tax purposes, the calculation of Percentage Stock Ownership (as defined in the Amended Articles) will effectively be based on a reduced number of shares outstanding, namely the total number of outstanding equity securities less the number of equity securities held by the Fire Victim Trust, the Utility and ShareCo. As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.

Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. Accordingly, PG&E Corporation will recognize income tax benefits and the corresponding DTA as the Fire Victim Trust sells shares of PG&E Corporation common stock, and the amounts of such benefits and assets will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were transferred to the Fire Victim Trust. On January 31, 2022 and April 14, 2022, the Fire Victim Trust exchanged 40,000,000 and 60,000,000 Plan Shares, respectively, for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. The Fire Victim Trust’s sale of 40,000,000 shares of PG&E Corporation common stock on January 31, 2022 resulted in a tax benefit of $135 million recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements for the quarter ended March 31, 2022.

Update on Ownership Restrictions in PG&E Corporation’s Amended Articles

As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn, attributed to PG&E Corporation for income tax purposes. Consequently, any shares of PG&E Corporation common stock owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,465,220,279 shares outstanding as of April 21, 2022, only 1,609,733,099 shares (the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of April 21, 2022, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of April 21, 2022 was 3.10% of outstanding shares. On January 31, 2022 and April 14, 2022, the Fire Victim Trust exchanged 40,000,000 and 60,000,000 Plan Shares, respectively, for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. As of April 21, 2022, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 100,000,000 shares of PG&E Corporation common stock.

RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation’s and the Utility’s operating results for the three months ended March 31, 2022 and 2021. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

14


PG&E Corporation

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below.  The following table provides a summary of net income (loss) attributable to common shareholders for the three months ended March 31, 2022 and 2021:
Three Months Ended March 31,
(in millions)20222021
Consolidated Total$475 $120 
PG&E Corporation(52)(54)
Utility$527 $174 

PG&E Corporation’s net loss primarily consists of income taxes and interest expense on long-term debt.

Utility

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three months ended March 31, 2022 and 2021.  The table separately identifies the revenues and costs that impacted earnings from those that did not impact earnings.  In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs), and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings. 

15


Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility’s costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on rate base.  Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets.
Three Months Ended March 31, 2022Three Months Ended March 31, 2021
Revenues/Costs:Revenues/Costs:
(in millions)That Impacted EarningsThat Did Not Impact EarningsTotal UtilityThat Impacted EarningsThat Did Not Impact EarningsTotal Utility
Electric operating revenues$2,904 $1,254 $4,158 $2,343 $1,052 $3,395 
Natural gas operating revenues922 718 1,640 897 424 1,321 
   Total operating revenues3,826 1,972 5,798 3,240 1,476 4,716 
Cost of electricity— 502 502 — 590 590 
Cost of natural gas— 561 561 — 307 307 
Operating and maintenance
2,085 1,022 3,107 1,708 623 2,331 
Wildfire-related claims, net of insurance recoveries(1)— (1)172 — 172 
Wildfire Fund expense118 — 118 119 — 119 
Depreciation, amortization, and decommissioning972 — 972 888 — 888 
   Total operating expenses3,174 2,085 5,259 2,887 1,520 4,407 
Operating income (loss)652 (113)539 353 (44)309 
Interest income
— — 
Interest expense
(364)— (364)(348)— (348)
Other income, net
43 113 156 89 44 133 
Reorganization items, net— — — (2)— (2)
Income before income taxes340  340 94  94 
Income tax benefit (1)
(190)(83)
Net income530 177 
Preferred stock dividend requirement (1)
Income Attributable to Common Stock$527 $174 
(1) These items impacted earnings for the three months ended March 31, 2022 and 2021.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for the three months ended March 31, 2022 and 2021, focusing on revenues and expenses that impacted earnings for these periods. 

Operating Revenues

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $586 million, or 18%, in the three months ended March 31, 2022, compared to the same period in 2021, primarily due to the recognition of approximately $310 million in revenues related to the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” below), increased base revenues authorized in the 2020 GRC, and additional revenues as authorized through the FERC formula rate.

16


Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings increased by $377 million or 22% in the three months ended March 31, 2022, compared to the same period in 2021, primarily due to the recognition of approximately $310 million of previously deferred expenses which was authorized by the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” below). Additionally, the Utility recognized approximately $85 million in expenses related to the Kincade SED Settlement as well as approximately $55 million in expenses related to the Kincade Stipulation and the Dixie Stipulation (each as defined in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1). These increases were partially offset by a decrease in insurance costs of approximately $55 million in the three months ended March 31, 2022, compared to the same period in 2021.

Wildfire-Related Claims, Net of Insurance Recoveries

Costs related to wildfires that impacted earnings decreased by $173 million, or 101%, in the three months ended March 31, 2022, compared to the same period in 2021. The Utility recognized pre-tax charges of $175 million related to the 2019 Kincade fire and pre-tax charges of $25 million related to the 2020 Zogg fire offset by $28 million of probable insurance recoveries in the three months ended March 31, 2021, with no comparable costs during the same period in 2022.

Wildfire Fund Expense

There was no material change to Wildfire Fund expense that impacted earnings for the periods presented.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses that impacted earnings increased by $84 million, or 9%, in the three months ended March 31, 2022, compared to the same period in 2021, primarily due to capital additions and an increase in decommissioning expense beginning in January 2022 as a result of the final 2018 Nuclear Decommissioning Cost Triennial Proceeding decision.

Interest Income

There was no material change to interest income that impacted earnings for the periods presented.

Interest Expense

Interest expense that impacted earnings increased by $16 million, or 5%, in the three months ended March 31, 2022, compared to the same period in 2021, primarily due to the issuance of additional long-term debt.

Other Income, Net

Changes to Other income, net that impact earnings are primarily driven by fluctuations in the balance of construction work in progress that impact equity AFUDC.

Reorganization Items, Net

There was no material change to reorganization items, net that impacted earnings for the periods presented.

Income Tax Benefit

Income tax benefit increased by $107 million in the three months ended March 31, 2022, compared to the same period in 2021, primarily due to a benefit recognized related to the sale of shares in the Fire Victim Trust in 2022 with no comparable benefit in the same period in 2021, partially offset by higher pretax income in the three months ended March 31, 2022, as compared to the same period in 2021.

17


The following table reconciles the income tax expense at the federal statutory rate to the income tax provision:
Three Months Ended March 31,
20222021
Federal statutory income tax rate21.0 %21.0 %
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)
(11.5)%(16.7)%
Effect of regulatory treatment of fixed asset differences (2)
(30.0)%(101.5)%
Tax credits
(0.9)%(3.1)%
Fire Victim Trust (3)
(29.8)%— %
Other, net(4.5)%13.1 %
Effective tax rate(55.7)%(87.2)%
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 2022 and 2021, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act.
(3) Includes the tax benefit for the sale of shares by the Fire Victim Trust in the three months ended March 31, 2022. See “Tax Matters” above and Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Utility Revenues and Costs that Did Not Impact Earnings

Fluctuations in revenues that did not impact earnings are primarily driven by procurement costs.  See below for more information.

Cost of Electricity

The Utility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities.  Cost of electricity also includes net sales (Utility owned generation and third parties) in the CAISO electricity markets. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.  The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity.
Three Months Ended March 31,
(in millions)20222021
Cost of purchased power, net
$434 $530 
Fuel used in generation facilities68 60 
Total cost of electricity$502 $590 

18


Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities.  See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.  The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of storage and transportation, and changes in customer demand. 
Three Months Ended March 31,
(in millions)20222021
Cost of natural gas sold$522 $270 
Transportation cost of natural gas sold3937
Total cost of natural gas$561 $307 

Operating and Maintenance Expenses

The Utility’s operating expenses that did not impact earnings include certain costs that the Utility is authorized to recover as incurred. If the Utility were to spend more than authorized amounts, these expenses could have an impact to earnings.

Other Income, Net

The Utility’s other income, net that did not impact earnings includes pension and other post-retirement benefit costs that fluctuate primarily from market and interest rate changes.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations, finance capital expenditures, make scheduled principal and interest payments, and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of capital. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% equity and 48% debt and preferred stock and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s emergence from Chapter 11.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, and fund equity contributions to the Utility depends on the level of cash on hand, cash received from the Utility, and PG&E Corporation’s access to the capital and credit markets.

PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. The collateral posting provisions for some of the Utility’s power and natural gas commodity, and transportation and service agreements state that if the Utility’s credit ratings were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some or all of its net liability positions. The Utility’s credit ratings fell below investment grade in January 2019, at which time the Utility was required to post additional collateral under its commodity purchase agreements. A further downgrade would not materially impact the collateral postings for procurement activity. See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

19


COVID-19

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic. The outbreak of the COVID-19 pandemic, the emergence of variant strains of the virus (including Delta and Omicron), and the resulting economic conditions and government orders have had and will continue to have a significant adverse impact on the Utility’s customers and, as a result, these circumstances have impacted and will continue to impact the Utility for an indeterminate period of time. The principal areas of near-term impact include liquidity, financial results and business operations, stemming primarily from the ongoing economic hardship of the Utility’s customers, the moratorium on service disconnections for residential and small business customers and for eligible medium and large commercial and industrial customers that expired on September 30, 2021, the CPUC’s “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections” and an observed reduction in non-residential electrical load. The Utility’s accounts receivable balances over 30 days outstanding as of March 31, 2022, were approximately $956 million, or $724 million higher as compared to the balance as of December 31, 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic. The Utility expects to continue experiencing an impact on monthly cash collections for as long as current COVID-19 circumstances persist.

As of March 31, 2022, PG&E Corporation and the Utility had access to approximately $2.4 billion of total liquidity comprised of approximately $199 million of Utility cash, $48 million of PG&E Corporation cash and $2.2 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities. The 2022 cost of capital application was filed off-cycle based on the extraordinary event of the COVID-19 pandemic and related government response. See “Cost of Capital Proceedings” below for more information.

The Utility has established the CPPMA memorandum accounts for tracking costs related to the CPUC’s emergency authorization and order, which, as of March 31, 2022, totaled $48 million and is reflected in Long-term regulatory assets on the Condensed Consolidated Balance Sheets. In addition to the $48 million recorded to the CPPMA, the Utility recorded approximately $104 million of undercollections from residential customers from June 11, 2020 to March 31, 2022 to the RUBA, which has been approved by the CPUC and is reflected in Regulatory balancing accounts receivable on the Condensed Consolidated Balance Sheets. During the quarter ended December 31, 2021, there was an adjustment to the RUBA current balancing accounts receivable of $180 million as a result of the expected CAPP funding, which was received on January 27, 2022.

The COVID-19 pandemic may continue to impact PG&E Corporation and the Utility financially, and PG&E Corporation and the Utility will continue to monitor the overall impact of the COVID-19 pandemic.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. 

Financial Resources

Equity Financings

On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement with the Agents, the Forward Sellers and the Forward Purchasers (each as defined in “At the Market Equity Distribution Program” in Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1.), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation’s common stock having an aggregate gross sales price of up to $400 million. The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into Forward Sale Agreements (as defined in “At the Market Equity Distribution Program” in Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) with the Forward Purchasers.

As of March 31, 2022, there was $400 million available under PG&E Corporation’s at the market equity distribution program for future offerings. During the quarter ended March 31, 2022, PG&E Corporation did not sell any shares pursuant to the Equity Distribution Agreement or any Forward Sale Agreement.

20


Debt Financings

On February 18, 2022, the Utility completed the sale of (i) $1 billion aggregate principal amount of 3.25% First Mortgage Bonds due 2024, (ii) $400 million aggregate principal amount of 4.20% First Mortgage Bonds due 2029, (iii) $450 million aggregate principal amount of 4.40% First Mortgage Bonds due 2032 and (iv) $550 million aggregate principal amount of 5.25% First Mortgage Bonds due 2052. The proceeds were used for the prepayment of a portion of the 18-month tranche loans pursuant to an existing term loan credit agreement (the “2020 Utility Term Loan Credit Agreement”), in an amount equal to $1.0 billion, and for general corporate purposes.

Credit Facilities

As of March 31, 2022, PG&E Corporation and the Utility had $500 million and $1.7 billion available under their respective $500 million and $4.0 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit (which was $1.0 billion as of March 31, 2022) and the facility availability. The facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program from time to time. As of April 25, 2022, the Receivables Securitization Program had a maximum borrowing base of $715 million and was fully drawn.

On March 31, 2022, the Utility prepaid in full the remaining portion of the 18-month tranche loans pursuant to the 2020 Utility Term Loan Credit Agreement, in a principal amount equal to $298 million. As a result of such prepayment, the 2020 Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

On April 4, 2022, the Utility entered into a term loan credit agreement (the “2022A Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $500 million (the “364-Day 2022A Tranche Loans”). The 364-Day 2022A Tranche Loans have a maturity date of April 3, 2023 and bear interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022A Tranche Loans on April 4, 2022.

On April 20, 2022, the Utility entered into a term loan credit agreement (the “2022B Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $125 million (the “364-Day 2022B Tranche Loans”) and two-year tranche loans in the aggregate principal amount of $400 million (the “2-Year 2022B Tranche Loans”). The 364-Day 2022B Tranche Loans have a maturity date of April 19, 2023 and the 2-Year 2022B Tranche Loans have a maturity date of April 19, 2024. The 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans bear interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans on April 20, 2022.

On April 20, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, add an uncommitted incremental facility which, subject to certain conditions precedent, allows the SPV to request an increase in the facility limit by an additional $500 million to an aggregate amount of $1.5 billion.

For more information, see “Credit Facilities” in Note 5 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018.

21


Subject to the dividend restrictions as described in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, payable on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million that will be accrued during the three-month period ending April 30, 2022, payable on May 15, 2022, to holders of record on April 29, 2022. It is uncertain as to when PG&E Corporation and the Utility will commence the payment of dividends on their common stock.

Utility Cash Flows

The Utility’s cash flows were as follows:
Three Months Ended March 31,
 (in millions)20222021
Net cash provided by operating activities$1,732 $1,283 
Net cash used in investing activities(2,330)(1,796)
Net cash provided by financing activities645 265 
Net change in cash, cash equivalents, and restricted cash$47 $(248)

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash.  During the three months ended March 31, 2022, net cash provided by operating activities increased by $449 million compared to the same period in 2021.  This increase was primarily due to a reduction in accounts receivable in 2022 resulting from the CAPP relief payment received in January 2022 to reduce the amounts owed by customer accounts in arrears. In addition, in the three months ended March 31, 2022, the Utility made a payment to the Fire Victim Trust of $592 million as compared to a payment of $758 million in the same period in 2021.

Future cash flow from operating activities will be affected by various factors, including:

the timing and amount of costs in connection with the 2019 Kincade fire, the 2020 Zogg fire, and the 2021 Dixie fire, and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries;

the timing and amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see “Wildfire-Related Securities Class Action” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Enforcement and Litigation Matters” and “Regulatory Matters” below for more information);

the severity, extent and duration of the global COVID-19 pandemic and its impact on the Utility’s service territory, the ability of the Utility to collect on its customer invoices, the ability of the Utility’s customers to pay their utility bills in full and in a timely manner, the ability of the Utility to offset these effects, including with spending reductions, and the ability of the Utility to recover through rates any losses incurred in connection with the COVID-19 pandemic, as well as the impact of the COVID-19 pandemic on the availability or cost of financing;

the timing and amounts of available funds to pay eligible claims for liabilities arising from future wildfires;

the timing and amount of substantially increasing costs in connection with the 2020-2022 WMP and the costs previously incurred in connection with the 2019 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information);

the timing and amount of premium payments related to wildfire insurance (see “Insurance Coverage” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information);

the timing of the gain to be returned to customers from the sale of the SFGO and transmission tower wireless licenses and the amounts incurred related to the move to and the leasing of the Lakeside Building; and
22



the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested.

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K.

Investing Activities

Net cash used in investing activities increased by $534 million during the three months ended March 31, 2022 as compared to the same period in 2021. This increase is due to higher capital expenditures, including additional system hardening and emergency response work performed in the first quarter of 2022. The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments.  The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.  The Utility estimates that it will incur between $7.8 billion and $8.9 billion in 2022 and between $7.9 billion and $10.4 billion in 2023. Additionally, future cash flows used in investing activities will be impacted by the timing and amount related to the intended purchase of the Lakeside Building.

Financing Activities

Net cash provided by financing activities increased by $380 million during the three months ended March 31, 2022 as compared to the same period in 2021. The increase was due to a $710 million reduction in net repayments under the available credit facilities, during the quarter ended March 31, 2022, as compared to the same period in 2021. The increase was partially offset by $350 million of proceeds received in the quarter ended March 31, 2021 from the sale of future revenue from transmission tower license sales, with no similar receipts in 2022.

Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments.  Additionally, future cash flows from financing activities will be affected by the timing and outcome of the Utility’s applications for a post-emergence securitization transaction and for a second AB 1054 securitization transaction. See “Application for Post-Emergence Securitization Transaction” and “Application for Second AB 1054 Securitization Transaction” below for more information. 

ENFORCEMENT AND LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Note 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1. that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

23


Enhanced Oversight and Enforcement Process

In the OII to Consider PG&E Corporation’s and the Utility’s Plan of Reorganization final decision, the CPUC adopted an EOEP designed to provide a roadmap for how the CPUC will monitor the Utility’s operational performance on an ongoing basis. The EOEP contains six steps that are triggered by specific events and includes enhanced reporting requirements and additional monitoring and oversight. These trigger events include failure to obtain an approved WMP, failure to comply with regulatory reporting requirements in the WMP, insufficient progress toward approved safety or risk-driven investments and failure to comply with or demonstrate sufficient progress toward certain metrics (some of which will be determined in an ongoing regulatory proceeding). The EOEP also contains provisions for the Utility to cure and permanently exit the EOEP if it can satisfy specific criteria. If the Utility is placed into the EOEP, actions taken would occur in coordination with the CPUC’s existing formal and informal reporting requirements and procedures. The EOEP does not replace or limit the CPUC’s regulatory authority, including the authority to issue Orders to Show Cause and OIIs and to impose fines and penalties. The EOEP requires the Utility to report the occurrence of a triggering event to the CPUC’s executive director no later than five business days after the date on which any member of senior management of the Utility becomes aware of the occurrence of a triggering event.

On August 18, 2021, the President of the CPUC informed the Utility that the CPUC staff intends to conduct a fact-finding review regarding a pattern of self-reported missed inspections and other self-reported safety incidents to determine whether a recommendation to advance the Utility further within the EOEP is warranted.

The Utility is unable to predict whether additional fines or penalties may be imposed, or other regulatory actions may be taken.

Vegetation Management

The CPUC placed the Utility into step 1 of the EOEP on April 15, 2021 and imposed additional reporting requirements on the Utility. The CPUC’s resolution states that a step 1 triggering event had occurred because the Utility had “made insufficient progress toward approved safety or risk-driven investments related to its electric business.” The resolution found that, based on the CPUC’s evaluation of the Utility’s EVM work in 2020, the Utility “is not sufficiently prioritizing its Enhanced Vegetation Management (“EVM”) based on risk” and “is not making risk-driven investments.” The resolution also found that “less than five percent of the EVM work” the Utility completed in 2020 “was on the 20 highest risk power lines according to [its] own risk rankings.”

As required by the CPUC’s resolution, the Utility submitted a corrective action plan to the CPUC’s Executive Director on May 6, 2021, which is designed to correct or prevent recurrence of the step 1 triggering event, or otherwise mitigate any ongoing safety risk or impact, as soon as practicable, among other things. The corrective action plan addressed the EVM situation that occurred in 2020 and provided a risk-informed EVM workplan for 2021. The Utility is required to update the information contained in the corrective action plan every 90 days. The Utility will remain in step 1 of the EOEP until the CPUC determines that the Utility has met the conditions of the corrective action plan. If the Utility does not adequately meet such conditions within the timeframe approved by the CPUC, the CPUC may place the Utility into a higher step of the EOEP, or the Utility may remain in step 1 of the EOEP if it demonstrates sufficient progress towards meeting such conditions.

The Utility is unable to predict the outcome of this regulatory process.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC, and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

During the three months ended March 31, 2022, the Utility continued to make progress on regulatory matters.

On January 31, 2022, the OEIS issued the Utility’s 2021 safety certification, which is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later.

24


On February 25, 2022 and February 28, 2022, the Utility submitted supplemental testimony for its 2023 GRC application to reflect the Utility’s integrated wildfire mitigation strategy, including the Utility’s proposals for the initial phase of undergrounding 10,000 miles of electric distribution powerlines in high fire risk areas throughout the Utility’s service area, the EPSS program, and its vegetation management program. The Utility’s updated revenue requirement request for the 2023 test year reduced its prior request from $15.46 billion to $15.34 billion. Also on February 25, 2022, the Utility submitted its 2022 WMP.

On February 28, 2022, the CPUC’s financing order authorizing the issuance of $7.5 billion of recovery bonds in connection with the post-emergence securitization became final and non-appealable.

On March 11, 2022, the Utility filed an application with the CPUC seeking authorization for a second transaction to securitize up to $1.7 billion of fire risk mitigation capital expenditure amounts that have been or will be incurred by the Utility in 2019 through 2022. 

On March 17, 2022, the CPUC approved the settlement agreement for the Utility’s 2018 CEMA application approving a total revenue requirement of $683 million plus interest for its expenses and capital costs.

Cost Recovery Proceedings

Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC rate requests or that have been deliberately excluded therefrom. These costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC also authorized balancing accounts with limitations or caps to cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, certain third-party wildfire claims, and insurance costs. While the Utility generally expects such costs to be recoverable, there can be no assurance that the CPUC will authorize the Utility to recover the full amount of its costs.

In recent years, the amount of the costs recorded in these accounts has increased. As of March 31, 2022, the Utility had recorded an aggregate amount of approximately $4.7 billion in costs not otherwise being recovered in existing revenue requirements, if any, for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, MGMA, and RTBA. Because rate recovery may require CPUC authorization for these accounts, there is a delay between when the Utility incurs costs and when it may recover those costs.

If the amount of the costs recorded in these accounts continues to increase, the delay between incurring and recovering costs lengthens, or the Utility does not recover the full amount of its costs, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility is unable to timely recover costs included in these applications.

For more information, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1., “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications,” and “Catastrophic Event Memorandum Account Application” below.

25


The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed in the first quarter of 2022 are summarized in the following table:

ProceedingRequestStatus
2020 WMCE
Revenue requirement of approximately $1.28 billion
Settlement agreement to recover $1.04 billion of revenue requirement filed September 2021. PD expected in October 2022.
2021 WMCE
Revenue requirement of approximately $1.47 billion
PD scheduled for the fourth quarter of 2022.
2018 CEMA
Revenue requirement of $763 million
Settlement agreement to recover $683 million plus interest approved March 2022.

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2020 WMCE Application

On September 30, 2020, the Utility filed an application with the CPUC requesting cost recovery of recorded expenditures related to wildfire mitigation and certain catastrophic events (the “2020 WMCE application”). The recorded expenditures, which exclude amounts disallowed as a result of the CPUC’s decision in the OII into the 2017 Northern California wildfires and the 2018 Camp fire, consist of $1.18 billion in expense and $801 million in capital expenditures, resulting in a proposed revenue requirement of approximately $1.28 billion.

The costs addressed in the 2020 WMCE application cover activities mainly during the years 2017 to 2019 and are incremental to those previously authorized in the Utility’s 2017 GRC and other proceedings. The Utility’s request includes amounts from the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million.

Given the CPUC’s prior approval of $447 million in interim rate relief (which includes interest), the Utility proposed to recover the remaining $868 million revenue requirement over a one-year period (following the conclusion of interim rate relief recovery). Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.

On September 21, 2021, the Utility and certain parties filed a motion with the CPUC seeking approval of a settlement agreement that would resolve all of the issues raised by the settling parties in the 2020 WMCE application. The settlement agreement proposes that the Utility recover a revenue requirement of $1.04 billion. The settlement agreement would authorize the Utility to continue to recover the interim revenue requirement of $447 million over a 17-month amortization period, followed by an additional revenue requirement of $591 million over a 24-month amortization period. On April 7, 2022, the CPUC extended the statutory deadline for a PD in this matter to October 1, 2022.

2021 WMCE Application

On September 16, 2021, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.6 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.47 billion (the “2021 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2020.

The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. The costs addressed in the 2021 WMCE application are incremental to those previously authorized in the Utility’s 2017 GRC, 2020 GRC, and other proceedings. The majority of the Utility’s proposed revenue requirement would be collected over a two-year period starting in January 2023.

The Utility’s requested revenue requirement includes amounts recorded to the VMBA of $592 million, the CEMA of $535 million, the WMBA of $149 million, and other memo accounts. On November 18, 2021, the Utility filed updates to the application, increasing total costs by $19.4 million. On December 30, 2021, the Utility filed supplemental testimony reducing the cost recovery ask of the COVID-19 CEMA costs by $12.2 million. The $12.2 million reduction was a result of identified avoided costs, such as employee business travel expenses and in-person training costs, due to the pandemic.

The scoping memo shows a schedule with the CPUC issuing a PD in the fourth quarter of 2022.
26



Catastrophic Event Memorandum Account Application

The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. The Utility has historically sought such costs through standalone CEMA applications. More recently, the Utility has sought CEMA-eligible costs through its WMCE applications.

In addition to the Utility’s responsibilities in responding to catastrophic events, in 2014, the CPUC directed the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. Through 2019, the costs associated with this work were tracked in the CEMA. In the 2020 GRC decision, the CPUC required the Utility to track these costs in the VMBA beginning January 1, 2020.

2018 CEMA Application

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. The Utility filed three revisions to this application, resulting in a total cost recovery request of $763 million.

On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs as requested by the Utility at that time. The interim rate relief was implemented, commencing on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund.

On March 17, 2022, the CPUC approved a settlement agreement authorizing the Utility to collect a total of $683 million plus interest for the 2018 CEMA application. As noted above, $373 million of the total amount had already been collected in interim rates. The interim rates became final and are no longer subject to refund. The remainder of the authorized revenue requirement that has yet to be collected will be amortized over a 12-month period, which the Utility expects to begin June 1, 2022.

Forward-Looking Rate Cases

The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in proceedings to adjust its regulated return on rate base.

Decisions in GRC proceedings are generally expected prior to the commencement of the period to which the rates would apply. However, delayed decisions in the Utility’s GRCs may cause the Utility to develop its budgets based on possible outcomes, rather than authorized amounts. When decisions are delayed, the CPUC typically provides rate relief to the Utility effective as of the commencement of the rate case period (not effective as of the date of the delayed decision). Nonetheless, the Utility’s spending during the period of the delay may exceed the authorized amount, without an ability for the Utility to seek cost recovery of such excess. If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risk associated with the lower level of work achieved compared to that funded by the CPUC.

Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected depending on the outcomes of these applications.

27


The Utility’s forward-looking rate cases that are pending, have pending appeals, or were completed in the first quarter of 2022 are summarized in the following table:
Rate CaseRequestStatus
2023 GRC
Revenue requirement of $15.34 billion for 2023
Filed amended application March 2022. A decision is expected in the third quarter of 2023.
2022 Cost of CapitalLeave cost of capital components at pre-2022 levels for 2022Filed August 2021. Briefing was completed in March 2022.
2023 Cost of CapitalIncrease ROE to 11% and cost of debt to 4.27%Filed April 2022.
2015 GT&S
Revenue requirement of $416 million
Settlement agreement to recover $356 million of revenue requirement filed July 2021.

2023 General Rate Case

On June 30, 2021, the Utility filed its 2023 GRC application with the CPUC (“the Original Application”). The 2023 GRC combined what had historically been separated into the GRC and GT&S rate cases. In the 2023 GRC, the CPUC will determine the annual amount of base revenues that the Utility will be authorized to collect from customers from 2023 through 2026 to recover its anticipated costs for gas distribution, gas transmission and storage, electric distribution, and electric generation and to provide the Utility an opportunity to earn its authorized rate of return. The Utility’s revenue requirements for other portions of its operations, such as electric transmission, and electricity, natural gas and power purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC. In the Original Application, the Utility proposed a series of safety, resiliency, and clean energy investments to further reduce wildfire risk and deliver safe, reliable, and clean energy service.

Between August 2021 and January 2022, the Utility served various updates to its 2023 GRC testimony. On February 25, 2022 and February 28, 2022, the Utility served supplemental testimony (the “Supplemental Testimony”) for its 2023 GRC to reflect the Utility’s integrated wildfire mitigation strategy, including the Utility’s proposals for the initial phase of undergrounding 10,000 miles of electric distribution powerlines in high fire risk areas throughout the Utility’s service area, the EPSS program, and its EVM program. On March 10, 2022, the Utility filed an amended application (the “Amended Application”) that revised the revenue requirement request in the Original Application.

In a GRC, the CPUC approves annual revenue requirements for the first year (a “test year”) of the GRC period and typically authorizes the Utility to receive annual increases in revenue requirements for the subsequent years of the GRC period (known as “attrition years”). The Utility’s Amended Application requested revenue requirements of $15.34 billion for its 2023 test year, an increase of $3.13 billion over the adopted 2020 GRC and 2019 GT&S revenue requirements for 2022 of $12.21 billion. The Amended Application’s requested revenue requirements for the 2023 test year reduced the Original Application’s request of $15.46 billion. The requested weighted-average GRC rate base for 2023 is approximately $49.18 billion, which corresponds to an increase of $9.97 billion over the authorized rate base for 2022 of $39.2 billion. The Utility also requested that the CPUC establish a ratemaking mechanism that would increase the Utility’s authorized GRC revenue requirements in 2024, 2025, and 2026 by $1.02 billion, $755 million, and $561 million, respectively. The Utility estimated its proposed revenue requirements for 2024, 2025, and 2026 would result in revenue requirement increases of 6.6%, 4.6%, and 3.3%, compared to its total estimated revenue requirements for 2023, 2024, and 2025, respectively. Over the GRC period of 2023-2026, the Utility plans to make average annual capital investments of approximately $9.61 billion in gas distribution, transmission and storage, electric distribution, and electric generation infrastructure, and to improve safety, reliability, and customer service.

The Utility intends to seek recovery of approximately $638 million in expense costs and $1.2 billion in capital expenditures in a second track of this proceeding or a later application, which are not included in the Amended Application. Those costs were incurred from 2019 to 2021 and are recorded in balancing or memorandum accounts for, among other work, wildfire mitigation and gas system safety improvements. The Utility also intends to seek recovery of costs incurred and recorded in balancing or memorandum accounts for similar work conducted in 2022.

In addition to coverage that may be available from the private insurance market, the Utility also proposed to use self-insurance as part of its wildfire insurance program as follows: (1) the Utility’s recommended approach, establishing a new self-insurance structure whereby the Utility would seek customer-funded self-insurance in the amount of $250 million annually and traditional private insurance procurement for amounts between the accumulated self-insurance balance and $1.0 billion; or, alternatively (2) continuing the currently authorized mechanism whereby the Utility seeks procurement of wildfire liability insurance instruments through the private insurance market and is authorized to use any unspent authorized revenue requirements on self-insurance.
28



The Utility does not seek recovery of compensation of PG&E Corporation’s and the Utility’s officers within the scope of 17 Code of Federal Regulations 240.3b-7.

On April 12, 2022, the CPUC issued a revised schedule indicating a decision on both tracks of this proceeding will be issued in the third quarter of 2023.

Cost of Capital Proceedings

2020 and 2022 Cost of Capital Applications

On December 19, 2019, the CPUC approved a final decision in the 2020 cost of capital application (the “2020 cost of capital application”), maintaining the Utility’s return on common equity at the 2019 level of 10.25% for the three-year period beginning January 1, 2020. The decision maintained the common equity component of the Utility’s capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking) at 52% and reduced its preferred stock component from 1% to 0.5%. The decision also approved the cost of debt requested by the Utility.

The Utility’s annual cost of capital adjustment mechanism, which allows for changes in the Utility’s authorized ROE and cost of debt, also remained unchanged by the final 2020 cost of capital application decision. The mechanism provides that in any year in which the difference between (i) the average Moody’s utility bond rates (as measured in the 12-month period from October through September (the “Index”)) and (ii) 4.5% exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility is to initiate this adjustment mechanism by filing an advice letter on or before October 15 of the year in which the mechanism triggered, to become effective on January 1 of the next year.

On August 23, 2021, the Utility filed an off-cycle 2022 cost of capital application with the CPUC based on the extraordinary event of the COVID-19 pandemic and related government response, which has decreased interest rates but has not reduced the cost of capital for electric utilities in general, and the Utility in particular, to the same extent as the overall financial markets (the “2022 cost of capital application”). The 2022 cost of capital application requested that the CPUC authorize the Utility's cost of capital for its electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2022 for 2022, 2023, and 2024. The Utility requested that the CPUC approve the Utility’s proposed ratemaking capital structure, ROE, cost of preferred stock, and cost of debt. The Utility proposed to establish a cost of long-term debt of 4.14%, a return on preferred stock of 5.52%, a ROE of 11%, and to retain the existing capital structure. The Utility also concurrently filed a motion requesting that the revenue requirement for the 2022 cost of capital be recorded in memorandum accounts to be trued-up following a final decision in this proceeding.

In September 2021, the cost of capital adjustment mechanism was triggered because the Index was 117 basis points below the benchmark. As the 2022 cost of capital application was pending, the Utility did not file the October 15, 2021 advice letter to adjust rates. Subsequently, on October 28, 2021, the CPUC ruled that the 2022 cost of capital application did not suspend the adjustment mechanism as requested by the application. The ruling also required that the Utility comply with the cost of capital mechanism by filing the information that would have been included in the October 15, 2021 advice letter in the 2022 cost of capital application proceeding on November 8, 2021, which the Utility did.

On December 17, 2021, the CPUC issued a final decision authorizing the Utility’s request to establish memorandum accounts to track revenue requirement changes starting on January 1, 2022 and leaving the cost of capital rates at current levels, subject to true-up based on the CPUC’s decision on the 2022 cost of capital application.

On December 24, 2021, the CPUC issued a scoping memo in the 2022 cost of capital application limiting the scope of the Utility’s 2022 cost of capital application to the 2022 cost of capital only.

To set the 2022 cost of capital, the CPUC will consider (i) whether there are extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022; and (ii) if so, whether to leave the cost of capital components at pre-2022 levels for the year 2022, or open a second phase to consider alternative cost of capital proposals for the year 2022. The Utility’s position is that there are extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022 and that the CPUC should leave the cost of capital components at pre-2022 levels for 2022. Briefing concluded on March 25, 2022.

29


If the CPUC determines that the 2022 cost of capital application establishes extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022 and leaves the Utility’s cost of capital components at pre-2022 levels for 2022, the cost of long-term debt would be 4.17%, the return on preferred stock would be 5.52%, and the ROE would be 10.25%. If the CPUC opens a second phase of the proceeding, the CPUC would set the cost of capital for 2022 based on alternative cost of capital proposals that would address the technical cost of capital material included within the Utility’s 2022 cost of capital application.

If the CPUC determines that there are not extraordinary circumstances that warrant a departure from the cost of capital mechanism for 2022, the cost of capital adjustment mechanism would operate and the cost of long-term debt would be 4.15%, the return on preferred stock would be 5.52%, and the ROE would be 9.67%. The resulting decrease in the CPUC jurisdictional gas and electric revenue requirement would be approximately $163 million ($99 million electric and $64 million gas).

2023 Cost of Capital Application

On April 20, 2022, the Utility filed an application with the CPUC requesting that the CPUC authorize the Utility's cost of capital for its electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2023 (the “2023 cost of capital application”).

In its 2023 cost of capital application, the Utility requested that the CPUC approve the Utility’s proposed ratemaking capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking), ROE, cost of preferred stock, and cost of debt. The Utility proposed to adopt a rate of ROE of 11% for test year 2023 and to retain the existing capital structure, which would result in a $226.2 million total increase above currently adopted electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage revenue requirements. The estimated revenue increase is based on the 2022 adopted electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base and does not reflect projected infrastructure investments beyond 2022.

The following table compares the currently authorized capital structure and rates of return with those requested in the Utility’s application for 2023. The Utility’s authorized rates of return for 2022 are currently subject to a separate cost of capital proceeding:
2022 Currently Authorized2023 Requested
CostCapital StructureWeighted CostCostCapital StructureWeighted
Cost
Common Equity10.25 %52.00 %5.33 %11.00 %52.00 %5.72 %
Preferred Stock5.52 %0.50 %0.03 %5.52 %0.50 %0.03 %
Long-term Debt4.17 %47.50 %1.98 %4.27 %47.50 %2.03 %
Weighted Average Cost of Capital100.00 %7.34 %100.00 %7.78 %

For 2023, the Utility expects that the proposed cost of capital, if adopted, would result in revenue requirement increases of approximately $138 million for electric generation and distribution and $53 million for gas distribution operations, assuming 2022 authorized rate base amounts from the 2020 GRC decision. The revenues for the gas transmission and storage operations would increase by approximately $35 million, assuming 2022 authorized rate base amounts from the 2019 GT&S decision. However, if the CPUC subsequently approves different electric and gas rate base amounts for the Utility in its 2023 GRC, which is currently pending before the CPUC, the revenue requirement changes resulting from the Utility’s requested ROE may differ from the amounts reflected in the 2023 cost of capital application for the period beyond 2022.

The Utility also requested that the CPUC approve an upward adjustment above the three-month commercial paper rate for interest on the Utility’s balancing and memorandum accounts to reflect the Utility’s actual cost of short-term debt. The Utility requested that the adjustment be set on an annual basis effective January 1 of each year based on the average difference between the three-month commercial paper rate and the Utility’s actual cost of short-term debt over the preceding twelve-month period from November through October. The Utility included an illustrative calculation using March 2021 to February 2022 showing an illustrative adjustment of 153 basis points, which would result in an estimated $69.3 million increase in recovery of short-term financing costs associated with its recent balancing and memorandum account balances. The actual revenue requirement impact of the short-term debt proposal would differ depending on the final adjustment set each year and the recorded balances in the balancing and memorandum accounts.

30


The cost of capital that is approved in this proceeding is expected to be effective until December 31, 2025, unless the cost of capital adjustment mechanism is triggered. (For more information on the cost of capital adjustment mechanism, see “2020 and 2022 Cost of Capital Applications” above.)

2015 Gas Transmission and Storage Rate Case

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of 2011 to 2014 capital spending in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. For more information regarding this proceeding, see Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Transmission Owner Rate Cases

Transmission Owner Rate Cases for 2015 and 2016 (the “TO16” and “TO17” rate cases, respectively)

As previously disclosed, on January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion granting an appeal of the FERC’s decisions in the TO16 and TO17 rate cases that had granted the Utility a 50-basis point ROE incentive adder for its continued participation in the CAISO. If the FERC concluded on remand that the Utility should no longer be authorized to receive the 50-basis point ROE incentive adder, the Utility would incur a refund obligation of $1 million and $8.5 million for TO16 and TO17, respectively. Those rate case decisions were remanded to the FERC for further proceedings consistent with the Ninth Circuit Court of Appeals’ opinion.

On July 18, 2019, the FERC issued its order on remand reaffirming its prior grant of the Utility’s request for the 50-basis point ROE adder.

On March 17, 2020, the FERC issued its order denying requests for rehearing that were previously filed by several parties. On May 11, 2020, the CPUC and a number of other parties filed a petition for review of the FERC’s orders in the Ninth Circuit Court of Appeals.

On March 17, 2022, the Ninth Circuit Court of Appeals upheld the FERC’s order granting the Utility the 50-basis point ROE incentive adder for CAISO participation. The order extinguished the Utility’s refund obligations that might have been required under the TO16 and TO17 had the Ninth Circuit Court of Appeals not found in the FERC’s favor.

Transmission Owner Rate Case for 2017 (the “TO18” rate case)

As previously disclosed, on July 29, 2016, the Utility filed its TO18 rate case with the FERC requesting a 2017 retail electric transmission revenue requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion.  The forecasted network transmission rate base for 2017 was $6.7 billion.  The Utility sought a ROE of 10.9%, which included an incentive component of 50-basis points for the Utility’s continuing participation in the CAISO. 

On October 15, 2020, the FERC issued an order that, among other things, rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. The order reopened the record for the limited purpose of allowing the participants to the proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020.

On December 17, 2020 and June 17, 2021, the FERC issued orders denying requests for rehearing submitted by the Utility and intervenors. In 2021, the Utility filed four appeals. The appeals related to two issues: (1) impact of the Tax Act on TO18 rates in January and February 2018 and (2) aspects of the rehearing order other than the Tax Act. The appeals have been consolidated and are currently being held in abeyance until the FERC addresses the ROE issue on rehearing.

As a result of an order denying rehearing on the common plant allocation, the Utility increased its regulatory liabilities for amounts previously collected during the TO18, TO19, and TO20 rate case periods from 2017 through the first quarter of 2022 by approximately $339 million. A portion of these common plant costs are expected to be recovered at the CPUC in a separate application and as a result, as of March 31, 2022, the Utility had recorded approximately $207 million to Regulatory assets.

31


On March 17, 2022, the FERC issued a further order in the TO18 rate case proceeding finding that 9.26% is the just and reasonable base ROE for the Utility. With the incentive component of 50-basis points for the Utility’s continuing participation in the CAISO, the resulting ROE would be 9.76%. As a result, the Utility increased its regulatory liability for the potential refund for TO18 by $30 million in the first quarter of 2022. On April 18, 2022, the Utility sought rehearing of the FERC’s determination of the base ROE finding.

Aside from the ultimate outcome of the ROE rehearing request and the common plant allocation, the FERC’s orders in the TO18 proceeding are not expected to result in a material impact on the Utility’s financial condition, results of operations, liquidity, and cash flows. Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s TO19 and TO20 rate cases. The ROE rehearing request will not impact the TO20 rate case. See “Transmission Owner Rate Case Revenue Subject to Refund” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Transmission Owner Rate Case for 2018 (the “TO19” rate case)

As previously disclosed, on July 27, 2017, the Utility filed its TO19 rate case with the FERC. On December 20, 2018, the FERC issued an order approving an all-party settlement filed by the Utility. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon the issuance of a final, non-appealable TO18 decision. Additionally, if the Ninth Circuit Court of Appeals were to determine that the Utility was not entitled to the 50-basis point incentive adder for the Utility’s continued CAISO participation, then the Utility would be obligated to make a refund to customers of approximately $25 million. On March 17, 2022, the Ninth Circuit Court of Appeals upheld the FERC’s order granting the Utility the 50-basis point ROE incentive adder for CAISO participation and eliminating the refund obligation. See “Transmission Owner Rate Cases for 2015 and 2016” above for a discussion of the incentive adder. As a result of the potential reduction to the TO18 revenue requirement, the Utility increased its regulatory liability for the potential refund for TO19 by $32 million in the first quarter of 2022. On April 18, 2022, the Utility sought rehearing of the FERC’s determination of the base ROE finding.

Transmission Owner Rate Case for 2019 (the “TO20” rate case)

As previously disclosed, on October 1, 2018, the Utility filed its TO20 rate case with the FERC requesting approval of a formula rate for the costs associated with the Utility’s electric transmission facilities. On November 30, 2018, the FERC issued an order accepting the Utility’s October 2018 filing, subject to hearings and refund, and established May 1, 2019 as the effective date for rate changes. The FERC also ordered that the hearings be held in abeyance pending settlement discussions among the parties.

On March 31, 2020, the Utility filed a partial settlement with the FERC, which the FERC approved on August 17, 2020. On October 15, 2020, the Utility filed a settlement with the FERC resolving all of the remaining issues in the formula rate proceedings, including the Utility’s ROE, capital structure, depreciation rates, as well as certain other aspects of the Utility’s formula rate. Specifically, the settlement establishes an all-in ROE of 10.45%; a fixed capital structure of 49.75% common stock, 49.75% debt, and 0.5% preferred stock; and fixed depreciation rates for various categories of transmission facilities (represented by individual FERC accounts). The term of the settlement continues until December 31, 2023 and the Utility will be required to file a replacement rate filing to be effective on January 1, 2024.

On December 30, 2020, the FERC approved the settlement without modification.

Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s TO19 and TO20 rate cases.


32


Other Regulatory Proceedings

Application for Post-Emergence Securitization Transaction

On April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to recover $7.5 billion of 2017 wildfire claims costs through securitization that is designed to be rate neutral to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with 2017 Northern California wildfires. Among other uses, as a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt. Specifically, the application requested administration of the stress test methodology approved in the CHT OIR and a determination that $7.5 billion in 2017 catastrophic wildfire costs and expenses are stress test costs and eligible for securitization. In this context, a securitization refers to a financing transaction where a special purpose financing vehicle issues new debt that is secured by the proceeds of a new recovery charge to Utility customers. The application also proposed a customer credit designed to equal the bond charges over the life of the bonds, which would insulate customers from the charge on customer bills associated with the bonds.

On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility’s 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. and approving a structure for the transaction. As requested, the decision authorized the Utility to establish a customer credit trust funded by PG&E Corporation’s shareholders, that will provide a monthly credit to customers that is anticipated to equal the securitized charges such that the securitization is designed to be rate neutral to customers. Subject to retention of the CPUC’s existing jurisdiction, the decision adopted a transaction structure comprised of four elements: (1) an initial shareholder contribution of $2.0 billion, with $1.0 billion to be contributed in 2022 and $1.0 billion to be contributed in 2024; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) sharing with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

In addition, on January 6, 2021, the Utility filed an additional application requesting that the CPUC issue a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires, which the CPUC subsequently granted on May 11, 2021.

On February 28, 2022, the decision finding $7.5 billion of stress test costs eligible for securitization and the financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable. The financing order authorized the issuance of bonds through the end of 2022. The number of bond series and tranches that can be issued in calendar year 2022, the size of those series and tranches, and whether sufficient market capacity exists for the full authorized amount of bonds in calendar year 2022 remain uncertain.

Application for Second AB 1054 Securitization Transaction

AB 1054 provides that the first $5.0 billion expended in the aggregate by California’s three large electric IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures has been allocated among the large electric IOUs in accordance with their Wildfire Fund allocation metrics. The Utility’s allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be financed using a structure that securitizes a dedicated customer charge. Pursuant to an earlier financing order issued by the CPUC authorizing the Utility’s initial application for AB 1054 securitization transaction, on November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. See Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

On March 11, 2022, the Utility filed an application with the CPUC seeking authorization for a second transaction to securitize up to $1.7 billion of fire risk mitigation capital expenditure amounts that have been or will be incurred by the Utility from 2019 through 2022.  The $1.7 billion reflects $212 million recorded and $1.16 billion forecasted capital expenditure amounts that were approved by the CPUC in the 2020 GRC and up to $350 million capital expenditure amounts pending in the 2020 WMCE proceeding, provided that a final decision approving such capital expenditure amounts is issued in the 2020 WMCE proceeding prior to the issuance of a financing order authorizing the second AB 1054 securitization transaction.  The final amount to be securitized will be based on actual recorded capital expenditures incurred by the Utility prior to the securitization transaction.

33


The application requests that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest, and would reduce rates on a present-value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a non-bypassable charge sufficient to pay debt service on the recovery bonds.  The application also requests that the CPUC exclude the securitized debt from the Utility’s ratemaking capital structure and adjust the Utility’s 2020 GRC and 2020 WMCE proceeding revenue requirements following the issuance of the recovery bonds. 

2020-2022 Wildfire Mitigation Plan

The Utility’s 2022 WMP was submitted on February 25, 2022. The 2022 WMP addressed the Utility’s wildfire safety programs and initiatives focused on reducing the potential for catastrophic wildfires related to electrical equipment, reducing the potential for fires to spread and reducing the impact of PSPS events. OEIS is scheduled to issue a draft decision on the 2022 WMP on May 26, 2022.

Electric Integrated Resource Planning and Related Procurement

On November 13, 2019, the CPUC issued a decision that takes a number of steps to address the potential for system RA shortages beginning in 2021. The decision required incremental procurement of system-level qualifying RA capacity of 3,300 MWs by all LSEs operating within the CAISO’s balancing area for the period from 2021 to 2023, of which the Utility is responsible for 716.9 MWs for its bundled customer portion. The decision required that at least 50% of LSE resource responsibilities come online by August 1, 2021, at least 75% by August 1, 2022, and the remaining by August 1, 2023. Additionally, the decision directed the IOUs to act as the backstop procurement agent for CCAs and energy service providers that choose not to voluntarily self-procure or that fail to meet their procurement responsibilities after electing to self-provide their assigned MWs of system RA capacity under the decision.

On June 30, 2021, the CPUC issued a mid-term reliability decision to address incremental electric system reliability needs between 2024 and 2026 due to, in part, the pending retirements of Diablo Canyon and once-through-cooling natural gas plants in Southern California by requiring at least 11,500 MW of additional net qualifying capacity to be procured by LSEs subject to the CPUC’s integrated resource planning authority. The decision set procurement requirements of 2,000 MW by 2023, an additional 6,000 MW by 2024, an additional 1,500 MW by 2025, and an additional 2,000 MW by 2026. The decision set the Utility’s share of the procurement at 2,302 MW of incremental net qualifying capacity.

On January 21, 2022, the Utility filed an advice letter with the CPUC seeking approval of a group of nine long-term RA agreements to meet a portion of its procurement requirements under the CPUC’s mid-term reliability decision. The agreements are each for a term of 15 years and collectively supply 1,598.7 MW of lithium-ion energy storage capacity with some projects expected to be operational in 2023 and others in 2024. On April 21, 2022, the CPUC approved a final resolution approving all nine long-term RA agreements as presented to the CPUC.

OIR to Revisit Net Energy Metering Tariffs

On August 17, 2020, the CPUC initiated a rulemaking proceeding to develop a successor to the existing NEM tariffs. The successor tariff is being developed pursuant to the requirements of AB 327. Under AB 327, the successor to the existing NEM tariffs should provide customer-generators with credit or compensation for electricity generated by their renewable facilities based on the value of that generation to all customers and allow customer-sited renewable generation to grow sustainably among different types of customers.

On December 13, 2021, the CPUC issued a PD that would reduce the compensation for new non-CARE NEM customers by about 80 percent for standalone solar and about 60 percent for solar-paired storage. Commercial customer NEM compensation would be reduced by about 35 percent. Additionally, the PD would reduce the legacy period for existing non-CARE NEM customers from 20 years to 15 years after which such customers would transition to the successor tariff. Comments and reply comments on the PD were filed in January 2022. The PD has not yet been scheduled to be voted on by the CPUC.

Self-Reports to the CPUC

The Utility self-reports certain errors and omissions to the CPUC. The Utility could face penalties, enforcement actions, or other adverse legal or regulatory consequences for these errors or omissions, including under the EOEP. The Utility is unable to predict the likelihood and the amount of potential fines or penalties, if any, related to these matters.

34


Electric Asset Inspections

The Utility has notified the CPUC of various errors relating to inspections and maintenance of its electric assets or implementation of WMP initiatives. These notices include missed inspections or the inability to locate records evidencing performance of inspections required under CPUC GOs 95 and 165 (including failure to perform inspections in compliance with GO 165 of approximately 55,000 poles in 2020) and errors regarding reporting meeting targets set by the Utility’s 2020 WMP. In these notices, the Utility describes the failures and corrective actions the Utility is taking to remediate these issues and to prevent recurrence in the future. Among other corrective measures, the Utility has developed short-term and longer-term systemic corrective actions to address these errors, including performing enhanced inspections for poles with outdated or incomplete GO 165 inspection records and strengthening the Utility’s asset registry, as well as corrective actions regarding reporting on the progress toward WMP targets.

The Utility continues to evaluate whether there are additional failures to comply with GOs 95 and 165 and the 2020 WMP, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews.

Subsurface Electric Ducts

On October 21, 2021, the Utility notified the CPUC of inconsistent application of the requirements to locate and mark empty subsurface electric ducts in accordance with Government Code sections 4216(k), 4216(s) and 4216.3(a)(1)(A). On December 30, 2021, the Utility submitted a corrective action plan to the SED and is implementing the plan.

LEGISLATIVE AND REGULATORY INITIATIVES

Vaccine Mandates

On September 9, 2021, President Biden issued an EO that would require certain COVID-19 precautions for government contractors and their subcontractors, including mandatory employee vaccination. The requirements under the EO are currently stayed pending the outcome of ongoing litigation. The ultimate implementation of the EO could result in workplace disruptions, employee attrition, and difficulty securing future labor needs.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public.  These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous wastes; the reporting and reduction of carbon dioxide and other greenhouse gas emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. See Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this quarterly report on Form 10-Q, as well as “Item 1A. Risk Factors” and Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K.

RISK MANAGEMENT ACTIVITIES

PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit.

The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows.  The Utility uses derivative instruments only for risk mitigation purposes and not for speculative purposes.  The Utility’s risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments.  Some contracts are accounted for as leases.  The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate.  Credit limits and credit quality are monitored periodically.  These activities are discussed in detail in the 2021 Form 10-K.  There were no significant developments to the Utility’s and PG&E Corporation’s risk management activities during the three months ended March 31, 2022.

35


CRITICAL ACCOUNTING ESTIMATES

The preparation of the Condensed Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, AROs, contributions to the Wildfire Fund, and pension and other post-retirement benefit plans to be critical accounting policies. These policies are considered critical accounting estimates due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates and assumptions. These accounting estimates and their key characteristics are discussed in detail in the 2021 Form 10-K.


36


ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per share amounts)
(Unaudited)
 Three Months Ended March 31,
 20222021
Operating Revenues  
Electric$4,158 $3,395 
Natural gas1,640 1,321 
Total operating revenues
5,798 4,716 
Operating Expenses  
Cost of electricity502 590 
Cost of natural gas561 307 
Operating and maintenance3,110 2,336 
Wildfire-related claims, net of recoveries(1)172 
Wildfire Fund expense118 119 
Depreciation, amortization, and decommissioning972 888 
Total operating expenses
5,262 4,412 
Operating Income536 304 
Interest income8 2 
Interest expense(419)(408)
Other income, net149 127 
Income Before Income Taxes274 25 
Income tax benefit(204)(98)
Net Income478 123 
Preferred stock dividend requirement of subsidiary3 3 
Income Available for Common Shareholders$475 $120 
Weighted Average Common Shares Outstanding, Basic1,986 1,985 
Weighted Average Common Shares Outstanding, Diluted2,134 2,131 
Net Income Per Common Share, Basic$0.24 $0.06 
Net Income Per Common Share, Diluted$0.22 $0.06 

See accompanying Notes to the Condensed Consolidated Financial Statements.
37


PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended March 31,
(in millions)20222021
Net Income $478 $123 
Other Comprehensive Income  
Pension and other postretirement benefit plans obligations (net of taxes of $0 and $0, respectively)
 1 
Total other comprehensive income  1 
Comprehensive Income 478 124 
Preferred stock dividend requirement of subsidiary3 3 
Comprehensive Income Available for Common Shareholders$475 $121 

See accompanying Notes to the Condensed Consolidated Financial Statements.

38


PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
(Unaudited)
 Balance At
 March 31, 2022December 31, 2021
ASSETS  
Current Assets  
Cash and cash equivalents$247 $291 
Restricted cash29 16 
Accounts receivable
Customers (net of allowance for doubtful accounts of $180 million and $171 million at respective dates)
(includes $1.84 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $180 million and $171 million at respective dates)
2,080 2,345 
Accrued unbilled revenue (includes $976 million and $1.09 billion related to VIEs at respective dates)
1,070 1,207 
Regulatory balancing accounts3,165 2,999 
Other1,695 1,784 
Regulatory assets384 496 
Inventories
Gas stored underground and fuel oil29 44 
Materials and supplies589 552 
Wildfire Fund asset461 461 
Other627 882 
Total current assets10,376 11,077 
Property, Plant, and Equipment  
Electric71,001 69,482 
Gas26,474 25,979 
Construction work in progress3,666 3,479 
Financing lease and other20 20 
Total property, plant, and equipment101,161 98,960 
Accumulated depreciation(29,656)(29,134)
Net property, plant, and equipment71,505 69,826 
Other Noncurrent Assets  
Regulatory assets9,167 9,207 
Nuclear decommissioning trusts3,635 3,798 
Operating lease right of use asset1,139 1,234 
Wildfire Fund asset5,198 5,313 
Income taxes receivable9 9 
Other (includes net noncurrent accounts receivable of $115 million and $187 million related to VIEs, net of noncurrent allowance for doubtful accounts of $11 million and $15 million at respective dates)
2,902 2,863 
Total other noncurrent assets22,050 22,424 
TOTAL ASSETS$103,931 $103,327 

See accompanying Notes to the Condensed Consolidated Financial Statements.
39


PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
(Unaudited)
Balance At
March 31, 2022December 31, 2021
LIABILITIES AND EQUITY  
Current Liabilities  
Short-term borrowings$1,854 $2,184 
Long-term debt, classified as current (includes $32 million and $18 million related to VIEs at respective dates)
4,553 4,481 
Accounts payable
Trade creditors2,389 2,855 
Regulatory balancing accounts1,676 1,121 
Other814 679 
Operating lease liabilities466 468 
Interest payable331 481 
Wildfire-related claims2,091 2,722 
Other2,386 2,436 
Total current liabilities16,560 17,427 
Noncurrent Liabilities  
Long-term debt (includes $1.83 billion and $1.82 billion related to VIEs at respective dates)
39,123 38,225 
Regulatory liabilities11,563 11,999 
Pension and other postretirement benefits801 860 
Asset retirement obligations5,919 5,298 
Deferred income taxes3,162 3,177 
Operating lease liabilities739 810 
Other4,420 4,308 
Total noncurrent liabilities65,727 64,677 
Equity  
Shareholders' Equity  
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,987,472,590 and 1,985,400,540 shares outstanding at respective dates
34,726 35,129 
Treasury stock, at cost; 437,743,590 and 477,743,590 shares at respective dates
(4,447)(4,854)
Reinvested earnings(8,867)(9,284)
Accumulated other comprehensive loss(20)(20)
Total shareholders' equity21,392 20,971 
Noncontrolling Interest - Preferred Stock of Subsidiary252 252 
Total equity21,644 21,223 
TOTAL LIABILITIES AND EQUITY$103,931 $103,327 

See accompanying Notes to the Condensed Consolidated Financial Statements.

40


PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
(Unaudited)
 Three Months Ended March 31,
 20222021
Cash Flows from Operating Activities  
Net income