Constellation Energy - 10-Q quarterly report FY

March 31, 20262026Q112/3100018682750001168165False911111http://fasb.org/us-gaap/2025#OtherLiabilitiesNoncurrenthttp://fasb.org/us-gaap/2025#OtherLiabilitiesNoncurrentxbrli:sharesiso4217:USDiso4217:USDxbrli:sharesceg:segmentxbrli:pureutr:TWutr:GWceg:generationAssetutr:MWhutr:MMBTUceg:shortTonceg:counterpartyceg:plantceg:facilityceg:repurchaseAgreement00018682752026-01-012026-03-310001868275ceg:ConstellationEnergyGenerationLLCMember2026-01-012026-03-3100018682752026-04-3000018682752025-01-012025-03-3100018682752025-12-3100018682752024-12-3100018682752026-03-3100018682752025-03-310001868275us-gaap:AssetPledgedAsCollateralMemberus-gaap:VariableInterestEntityPrimaryBeneficiaryMember2026-03-310001868275us-gaap:AssetPledgedAsCollateralMemberus-gaap:VariableInterestEntityPrimaryBeneficiaryMember2025-12-310001868275us-gaap:NonrecourseMemberus-gaap:VariableInterestEntityPrimaryBeneficiaryMember2026-03-310001868275us-gaap:NonrecourseMemberus-gaap:VariableInterestEntityPrimaryBeneficiaryMember2025-12-310001868275us-gaap:CommonStockMember2025-12-310001868275us-gaap:RetainedEarningsMember2025-12-310001868275us-gaap:AccumulatedOtherComprehensiveIncomeMember2025-12-310001868275us-gaap:NoncontrollingInterestMember2025-12-310001868275us-gaap:RetainedEarningsMember2026-01-012026-03-310001868275us-gaap:NoncontrollingInterestMember2026-01-012026-03-310001868275us-gaap:CommonStockMember2026-01-012026-03-310001868275us-gaap:CommonStockMember2026-03-310001868275us-gaap:RetainedEarningsMember2026-03-310001868275us-gaap:AccumulatedOtherComprehensiveIncomeMember2026-03-310001868275us-gaap:NoncontrollingInterestMember2026-03-310001868275us-gaap:CommonStockMember2024-12-310001868275us-gaap:RetainedEarningsMember2024-12-310001868275us-gaap:AccumulatedOtherComprehensiveIncomeMember2024-12-310001868275us-gaap:NoncontrollingInterestMember2024-12-310001868275us-gaap:RetainedEarningsMember2025-01-012025-03-310001868275us-gaap:NoncontrollingInterestMember2025-01-012025-03-310001868275us-gaap:CommonStockMember2025-01-012025-03-310001868275us-gaap:AccumulatedOtherComprehensiveIncomeMember2025-01-012025-03-310001868275us-gaap:CommonStockMember2025-03-310001868275us-gaap:RetainedEarningsMember2025-03-310001868275us-gaap:AccumulatedOtherComprehensiveIncomeMember2025-03-310001868275us-gaap:NoncontrollingInterestMember2025-03-310001868275ceg:ConstellationEnergyGenerationLLCMember2025-01-012025-03-310001868275ceg:ConstellationEnergyGenerationLLCMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMember2024-12-310001868275ceg:ConstellationEnergyGenerationLLCMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMember2025-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:NonrelatedPartyMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:NonrelatedPartyMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:RelatedPartyMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:RelatedPartyMember2025-12-310001868275us-gaap:AssetPledgedAsCollateralMemberus-gaap:VariableInterestEntityPrimaryBeneficiaryMemberceg:ConstellationEnergyGenerationLLCMember2026-03-310001868275us-gaap:AssetPledgedAsCollateralMemberus-gaap:VariableInterestEntityPrimaryBeneficiaryMemberceg:ConstellationEnergyGenerationLLCMember2025-12-310001868275us-gaap:NonrecourseMemberus-gaap:VariableInterestEntityPrimaryBeneficiaryMemberceg:ConstellationEnergyGenerationLLCMember2026-03-310001868275us-gaap:NonrecourseMemberus-gaap:VariableInterestEntityPrimaryBeneficiaryMemberceg:ConstellationEnergyGenerationLLCMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:MembershipInterestMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:RetainedEarningsMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:AccumulatedOtherComprehensiveIncomeMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:NoncontrollingInterestMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:RetainedEarningsMember2026-01-012026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:NoncontrollingInterestMember2026-01-012026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:MembershipInterestMember2026-01-012026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:MembershipInterestMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:RetainedEarningsMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:AccumulatedOtherComprehensiveIncomeMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:NoncontrollingInterestMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:MembershipInterestMember2024-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:RetainedEarningsMember2024-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:AccumulatedOtherComprehensiveIncomeMember2024-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:NoncontrollingInterestMember2024-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:RetainedEarningsMember2025-01-012025-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:NoncontrollingInterestMember2025-01-012025-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:MembershipInterestMember2025-01-012025-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:AccumulatedOtherComprehensiveIncomeMember2025-01-012025-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:MembershipInterestMember2025-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:RetainedEarningsMember2025-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:AccumulatedOtherComprehensiveIncomeMember2025-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:NoncontrollingInterestMember2025-03-310001868275ceg:CalpineMember2026-01-072026-01-070001868275ceg:CalpineMember2026-01-070001868275srt:ScenarioForecastMemberceg:CalpineMember2026-06-300001868275srt:ScenarioForecastMemberceg:CalpineMember2027-06-300001868275ceg:RetailElectricSupplierPlatformMemberceg:CalpineMember2026-01-072026-01-070001868275ceg:NaturalGasGeothermalBatteryStorageAndSolarAssetsMemberceg:CalpineMember2026-01-072026-01-070001868275ceg:PJMMemberceg:LSPowerMember2026-01-310001868275ceg:ERCOTMemberceg:LSPowerMember2026-01-310001868275ceg:NaturalGasGeothermalBatteryStorageAndSolarAssetsMemberceg:LSPowerMember2026-01-012026-01-310001868275ceg:LSPowerMember2026-01-012026-01-310001868275ceg:CalpineMemberus-gaap:CommonStockMember2026-01-060001868275ceg:LSPowerMember2026-01-070001868275ceg:CalpineMember2026-03-310001868275ceg:CalpineMemberus-gaap:CustomerRelationshipsMember2026-01-072026-01-070001868275ceg:CalpineMemberus-gaap:TradeNamesMember2026-01-072026-01-070001868275ceg:CalpineMemberceg:EnergyContractsMember2026-01-072026-01-070001868275ceg:CalpineMember2026-01-012026-03-310001868275ceg:CalpineMember2025-01-012025-03-3100018682752026-04-012026-03-3100018682752027-01-012026-03-3100018682752028-01-012026-03-3100018682752029-01-012026-03-3100018682752030-01-012026-03-3100018682752031-01-012026-03-310001868275ceg:PowerRevenueMemberceg:PJMMemberceg:PowerAndPowerRelatedRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:PJMMemberceg:CapacityRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:PJMMemberceg:OtherRevenueTypeMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:PJMMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:MISOMemberceg:PowerAndPowerRelatedRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:MISOMemberceg:CapacityRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:MISOMemberceg:OtherRevenueTypeMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:MISOMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:ERCOTMemberceg:PowerAndPowerRelatedRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:ERCOTMemberceg:CapacityRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:ERCOTMemberceg:OtherRevenueTypeMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:ERCOTMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:NYISOMemberceg:PowerAndPowerRelatedRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:NYISOMemberceg:CapacityRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:NYISOMemberceg:OtherRevenueTypeMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:NYISOMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:ISONEMemberceg:PowerAndPowerRelatedRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:ISONEMemberceg:CapacityRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:ISONEMemberceg:OtherRevenueTypeMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:ISONEMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:WestMemberceg:PowerAndPowerRelatedRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:WestMemberceg:CapacityRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:WestMemberceg:OtherRevenueTypeMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:WestMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:SERCSPPMemberceg:PowerAndPowerRelatedRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:SERCSPPMemberceg:CapacityRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:SERCSPPMemberceg:OtherRevenueTypeMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:SERCSPPMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:InternationalMemberceg:PowerAndPowerRelatedRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:InternationalMemberceg:CapacityRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:InternationalMemberceg:OtherRevenueTypeMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:InternationalMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:PowerAndPowerRelatedRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:CapacityRevenuesMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:OtherRevenueTypeMember2026-01-012026-03-310001868275ceg:PowerRevenueMember2026-01-012026-03-310001868275ceg:GasRevenueMemberceg:PowerAndPowerRelatedRevenuesMember2026-01-012026-03-310001868275ceg:GasRevenueMemberceg:CapacityRevenuesMember2026-01-012026-03-310001868275ceg:GasRevenueMemberceg:OtherRevenueTypeMember2026-01-012026-03-310001868275ceg:GasRevenueMember2026-01-012026-03-310001868275ceg:OtherRevenueMemberceg:PowerAndPowerRelatedRevenuesMember2026-01-012026-03-310001868275ceg:OtherRevenueMemberceg:CapacityRevenuesMember2026-01-012026-03-310001868275ceg:OtherRevenueMemberceg:OtherRevenueTypeMember2026-01-012026-03-310001868275ceg:OtherRevenueMember2026-01-012026-03-310001868275ceg:PowerAndPowerRelatedRevenuesMember2026-01-012026-03-310001868275ceg:CapacityRevenuesMember2026-01-012026-03-310001868275ceg:OtherRevenueTypeMember2026-01-012026-03-310001868275ceg:PowerRevenueMemberceg:PJMMemberceg:PowerAndPowerRelatedRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:PJMMemberceg:CapacityRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:PJMMemberceg:OtherRevenueTypeMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:PJMMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:MISOMemberceg:PowerAndPowerRelatedRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:MISOMemberceg:CapacityRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:MISOMemberceg:OtherRevenueTypeMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:MISOMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:ERCOTMemberceg:PowerAndPowerRelatedRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:ERCOTMemberceg:CapacityRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:ERCOTMemberceg:OtherRevenueTypeMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:ERCOTMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:NYISOMemberceg:PowerAndPowerRelatedRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:NYISOMemberceg:CapacityRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:NYISOMemberceg:OtherRevenueTypeMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:NYISOMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:ISONEMemberceg:PowerAndPowerRelatedRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:ISONEMemberceg:CapacityRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:ISONEMemberceg:OtherRevenueTypeMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:ISONEMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:WestMemberceg:PowerAndPowerRelatedRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:WestMemberceg:CapacityRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:WestMemberceg:OtherRevenueTypeMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:WestMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:SERCSPPMemberceg:PowerAndPowerRelatedRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:SERCSPPMemberceg:CapacityRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:SERCSPPMemberceg:OtherRevenueTypeMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:SERCSPPMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:InternationalMemberceg:PowerAndPowerRelatedRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:InternationalMemberceg:CapacityRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:InternationalMemberceg:OtherRevenueTypeMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:InternationalMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:PowerAndPowerRelatedRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:CapacityRevenuesMember2025-01-012025-03-310001868275ceg:PowerRevenueMemberceg:OtherRevenueTypeMember2025-01-012025-03-310001868275ceg:PowerRevenueMember2025-01-012025-03-310001868275ceg:GasRevenueMemberceg:PowerAndPowerRelatedRevenuesMember2025-01-012025-03-310001868275ceg:GasRevenueMemberceg:CapacityRevenuesMember2025-01-012025-03-310001868275ceg:GasRevenueMemberceg:OtherRevenueTypeMember2025-01-012025-03-310001868275ceg:GasRevenueMember2025-01-012025-03-310001868275ceg:OtherRevenueMemberceg:PowerAndPowerRelatedRevenuesMember2025-01-012025-03-310001868275ceg:OtherRevenueMemberceg:CapacityRevenuesMember2025-01-012025-03-310001868275ceg:OtherRevenueMemberceg:OtherRevenueTypeMember2025-01-012025-03-310001868275ceg:OtherRevenueMember2025-01-012025-03-310001868275ceg:PowerAndPowerRelatedRevenuesMember2025-01-012025-03-310001868275ceg:CapacityRevenuesMember2025-01-012025-03-310001868275ceg:OtherRevenueTypeMember2025-01-012025-03-310001868275us-gaap:OperatingSegmentsMemberceg:ConstellationMidAtlanticMember2026-01-012026-03-310001868275us-gaap:OperatingSegmentsMemberceg:ConstellationMidwestMember2026-01-012026-03-310001868275us-gaap:OperatingSegmentsMemberceg:ConstellationNewYorkMember2026-01-012026-03-310001868275us-gaap:OperatingSegmentsMemberceg:ConstellationERCOTMember2026-01-012026-03-310001868275us-gaap:OperatingSegmentsMemberceg:ConstellationOtherRegionsMember2026-01-012026-03-310001868275us-gaap:OperatingSegmentsMemberceg:CalpineSegmentMember2026-01-012026-03-310001868275us-gaap:OperatingSegmentsMember2026-01-012026-03-310001868275us-gaap:MaterialReconcilingItemsMember2026-01-012026-03-310001868275us-gaap:OperatingSegmentsMemberceg:ConstellationMidAtlanticMember2025-01-012025-03-310001868275us-gaap:OperatingSegmentsMemberceg:ConstellationMidwestMember2025-01-012025-03-310001868275us-gaap:OperatingSegmentsMemberceg:ConstellationNewYorkMember2025-01-012025-03-310001868275us-gaap:OperatingSegmentsMemberceg:ConstellationERCOTMember2025-01-012025-03-310001868275us-gaap:OperatingSegmentsMemberceg:ConstellationOtherRegionsMember2025-01-012025-03-310001868275us-gaap:OperatingSegmentsMember2025-01-012025-03-310001868275us-gaap:MaterialReconcilingItemsMember2025-01-012025-03-310001868275us-gaap:MaterialReconcilingItemsMemberus-gaap:ProductAndServiceOtherMember2026-01-012026-03-310001868275us-gaap:MaterialReconcilingItemsMemberus-gaap:ProductAndServiceOtherMember2025-01-012025-03-310001868275ceg:NuclearPTCsMember2026-03-310001868275ceg:NuclearPTCsMember2025-12-310001868275ceg:NuclearPTCsMember2025-01-012025-12-310001868275ceg:NuclearPTCsMember2026-01-012026-03-310001868275ceg:NuclearPTCsMember2025-01-012025-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:CustomerAccountsReceivableMember2026-03-310001868275ceg:CustomerAccountsReceivableMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:OtherAccountsReceivableMember2026-03-310001868275ceg:OtherAccountsReceivableMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:CustomerAccountsReceivableMember2025-12-310001868275ceg:CustomerAccountsReceivableMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:OtherAccountsReceivableMember2025-12-310001868275ceg:OtherAccountsReceivableMember2025-12-310001868275us-gaap:ElectricGenerationEquipmentMember2026-03-310001868275us-gaap:ElectricGenerationEquipmentMember2025-12-310001868275us-gaap:NuclearFuelMember2026-03-310001868275us-gaap:NuclearFuelMember2025-12-310001868275us-gaap:ConstructionInProgressMember2026-03-310001868275us-gaap:ConstructionInProgressMember2025-12-310001868275ceg:CalpineMemberceg:ElectricAssetsMember2026-03-310001868275ceg:CalpineMemberceg:CWIPAssetsMember2026-03-310001868275ceg:NuclearDecommissioningMember2025-12-310001868275ceg:NuclearDecommissioningMember2026-01-012026-03-310001868275ceg:NuclearDecommissioningMember2026-03-310001868275us-gaap:AssetsTotalMember2026-03-310001868275us-gaap:AssetsTotalMember2025-12-310001868275ceg:CommonwealthEdisonCoAffiliateMembersrt:AffiliatedEntityMember2026-03-310001868275ceg:CommonwealthEdisonCoAffiliateMembersrt:AffiliatedEntityMember2025-12-310001868275ceg:PecoEnergyCoAffiliateMembersrt:AffiliatedEntityMember2026-03-310001868275ceg:PecoEnergyCoAffiliateMembersrt:AffiliatedEntityMember2025-12-310001868275ceg:CenterPointEnergyHoustonElectricLLCMembersrt:AffiliatedEntityMember2026-03-310001868275ceg:CenterPointEnergyHoustonElectricLLCMembersrt:AffiliatedEntityMember2025-12-310001868275ceg:AEPTexasInc.Membersrt:AffiliatedEntityMember2026-03-310001868275ceg:AEPTexasInc.Membersrt:AffiliatedEntityMember2025-12-310001868275ceg:NonnuclearDecommissioningAssetRetirementObligationMember2025-12-310001868275ceg:NonnuclearDecommissioningAssetRetirementObligationMember2026-01-012026-03-310001868275ceg:NonnuclearDecommissioningAssetRetirementObligationMember2026-03-310001868275us-gaap:OtherNoncurrentLiabilitiesMembersrt:AffiliatedEntityMemberceg:SeparationFromParentMember2026-03-310001868275us-gaap:OtherNoncurrentLiabilitiesMembersrt:AffiliatedEntityMemberceg:SeparationFromParentMember2025-12-310001868275ceg:SeparationFromParentMember2026-03-310001868275ceg:SeparationFromParentMember2025-12-3100018682752026-02-012026-02-280001868275us-gaap:PensionPlansDefinedBenefitMember2026-01-012026-03-310001868275us-gaap:PensionPlansDefinedBenefitMember2025-01-012025-03-310001868275us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2026-01-012026-03-310001868275us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2025-01-012025-03-310001868275us-gaap:CommodityContractMemberus-gaap:NotDesignatedAsHedgingInstrumentEconomicHedgeMember2026-03-310001868275us-gaap:CommodityContractMemberceg:CollateralMember2026-03-310001868275us-gaap:CommodityContractMemberceg:NettingMember2026-03-310001868275us-gaap:CommodityContractMember2026-03-310001868275us-gaap:CommodityContractMemberus-gaap:NotDesignatedAsHedgingInstrumentEconomicHedgeMember2025-12-310001868275us-gaap:CommodityContractMemberceg:CollateralMember2025-12-310001868275us-gaap:CommodityContractMemberceg:NettingMember2025-12-310001868275us-gaap:CommodityContractMember2025-12-310001868275us-gaap:ElectricityMember2026-01-012026-03-310001868275us-gaap:ElectricityMember2025-01-012025-12-310001868275srt:NaturalGasReservesMember2026-01-012026-03-310001868275srt:NaturalGasReservesMember2025-01-012025-12-310001868275ceg:EmissionsMember2026-01-012026-03-310001868275ceg:EmissionsMember2025-01-012025-12-310001868275us-gaap:CommodityContractMemberus-gaap:NotDesignatedAsHedgingInstrumentEconomicHedgeMemberceg:OperatingRevenueMember2026-01-012026-03-310001868275us-gaap:CommodityContractMemberus-gaap:NotDesignatedAsHedgingInstrumentEconomicHedgeMemberceg:OperatingRevenueMember2025-01-012025-03-310001868275us-gaap:CommodityContractMemberus-gaap:NotDesignatedAsHedgingInstrumentEconomicHedgeMemberceg:PurchasedPowerAndFuelMember2026-01-012026-03-310001868275us-gaap:CommodityContractMemberus-gaap:NotDesignatedAsHedgingInstrumentEconomicHedgeMemberceg:PurchasedPowerAndFuelMember2025-01-012025-03-310001868275us-gaap:CommodityContractMemberus-gaap:NotDesignatedAsHedgingInstrumentEconomicHedgeMember2026-01-012026-03-310001868275us-gaap:CommodityContractMemberus-gaap:NotDesignatedAsHedgingInstrumentEconomicHedgeMember2025-01-012025-03-310001868275us-gaap:InterestRateSwapMemberus-gaap:NotDesignatedAsHedgingInstrumentEconomicHedgeMember2026-03-310001868275us-gaap:InterestRateSwapMemberus-gaap:NotDesignatedAsHedgingInstrumentEconomicHedgeMember2025-12-310001868275us-gaap:ExternalCreditRatingInvestmentGradeMemberus-gaap:FairValueConcentrationOfRiskMaximumAmountOfLossMember2026-01-012026-03-310001868275us-gaap:ExternalCreditRatingInvestmentGradeMemberceg:CreditCollateralMember2026-01-012026-03-310001868275us-gaap:ExternalCreditRatingInvestmentGradeMemberceg:NetExposureMember2026-01-012026-03-310001868275us-gaap:ExternalCreditRatingInvestmentGradeMemberceg:NumberOfCounterpartiesGreaterThanTenPercentOfNetExposureMember2026-03-310001868275us-gaap:ExternalCreditRatingInvestmentGradeMemberceg:NetExposureOfCounterpartiesGreaterThanTenPercentOfNetExposureMember2026-01-012026-03-310001868275us-gaap:ExternalCreditRatingNonInvestmentGradeMemberus-gaap:FairValueConcentrationOfRiskMaximumAmountOfLossMember2026-01-012026-03-310001868275us-gaap:ExternalCreditRatingNonInvestmentGradeMemberceg:CreditCollateralMember2026-01-012026-03-310001868275us-gaap:ExternalCreditRatingNonInvestmentGradeMemberceg:NetExposureMember2026-01-012026-03-310001868275us-gaap:ExternalCreditRatingNonInvestmentGradeMemberceg:NumberOfCounterpartiesGreaterThanTenPercentOfNetExposureMember2026-03-310001868275us-gaap:ExternalCreditRatingNonInvestmentGradeMemberceg:NetExposureOfCounterpartiesGreaterThanTenPercentOfNetExposureMember2026-01-012026-03-310001868275us-gaap:InternalInvestmentGradeMemberus-gaap:FairValueConcentrationOfRiskMaximumAmountOfLossMember2026-01-012026-03-310001868275us-gaap:InternalInvestmentGradeMemberceg:CreditCollateralMember2026-01-012026-03-310001868275us-gaap:InternalInvestmentGradeMemberceg:NetExposureMember2026-01-012026-03-310001868275us-gaap:InternalInvestmentGradeMemberceg:NumberOfCounterpartiesGreaterThanTenPercentOfNetExposureMember2026-03-310001868275us-gaap:InternalInvestmentGradeMemberceg:NetExposureOfCounterpartiesGreaterThanTenPercentOfNetExposureMember2026-01-012026-03-310001868275us-gaap:InternalNoninvestmentGradeMemberus-gaap:FairValueConcentrationOfRiskMaximumAmountOfLossMember2026-01-012026-03-310001868275us-gaap:InternalNoninvestmentGradeMemberceg:CreditCollateralMember2026-01-012026-03-310001868275us-gaap:InternalNoninvestmentGradeMemberceg:NetExposureMember2026-01-012026-03-310001868275us-gaap:InternalNoninvestmentGradeMemberceg:NumberOfCounterpartiesGreaterThanTenPercentOfNetExposureMember2026-03-310001868275us-gaap:InternalNoninvestmentGradeMemberceg:NetExposureOfCounterpartiesGreaterThanTenPercentOfNetExposureMember2026-01-012026-03-310001868275us-gaap:FairValueConcentrationOfRiskMaximumAmountOfLossMember2026-01-012026-03-310001868275ceg:CreditCollateralMember2026-01-012026-03-310001868275ceg:NetExposureMember2026-01-012026-03-310001868275ceg:NumberOfCounterpartiesGreaterThanTenPercentOfNetExposureMember2026-03-310001868275ceg:NetExposureOfCounterpartiesGreaterThanTenPercentOfNetExposureMember2026-01-012026-03-310001868275ceg:InvestorOwnedUtilitiesMarketersPowerProducersMemberceg:NetExposureMember2026-01-012026-03-310001868275ceg:FinancialInstitutionsMemberceg:NetExposureMember2026-01-012026-03-310001868275ceg:EnergyCooperativesAndMunicipalitiesMemberceg:NetExposureMember2026-01-012026-03-310001868275ceg:OtherMemberceg:NetExposureMember2026-01-012026-03-310001868275ceg:CalpineMember2026-01-310001868275ceg:CorporateDebtMemberceg:CalpineMember2026-01-310001868275ceg:VariousNonRecourseDebtAndProjectFinancingArrangementsMemberceg:CalpineMember2026-01-310001868275ceg:CalpineMemberus-gaap:SeniorNotesMember2026-01-310001868275ceg:CorporateDebtMember2026-01-012026-01-310001868275ceg:SeniorSecuredFirstLienNotesMember2026-02-012026-02-280001868275ceg:SeniorSecuredFirstLienNotesMember2026-03-012026-03-310001868275ceg:GPCFirstLienSeniorSecuredTermLoanFacilityMemberceg:CalpineMember2026-01-310001868275ceg:GPCFirstLienSeniorSecuredTermLoanSubFacilityMemberceg:CalpineMember2026-01-310001868275ceg:GPCFirstLienSeniorSecuredTermLoanFacilityMemberceg:CalpineMember2026-01-012026-03-310001868275ceg:GPCFirstLienSeniorSecuredTermLoanFacilityMemberceg:CalpineMember2026-03-310001868275ceg:GPCFirstLienSeniorSecuredTermLoanSubFacilityMemberceg:CalpineMember2026-03-310001868275ceg:CCFCFirstLienSeniorSecuredTermLoanFacilityMemberceg:CalpineMember2026-01-310001868275ceg:CCFCFirstLienSeniorSecuredTermLoanFacilityMemberceg:CalpineMember2026-01-012026-03-310001868275ceg:CCFCFirstLienSeniorSecuredTermLoanFacilityMemberceg:CalpineMember2026-03-310001868275ceg:CDHIRevolverMemberceg:CalpineMember2026-01-310001868275ceg:CDHIRevolverRenewableEnergyProjectConstructionMemberceg:CalpineMember2026-01-310001868275ceg:CDHIRevolverMemberceg:CalpineMember2026-01-012026-02-280001868275ceg:CDHIRevolverMemberceg:CalpineMember2026-03-012026-03-310001868275ceg:CDHIRevolverMember2026-03-012026-03-310001868275ceg:CDHIRevolverMemberus-gaap:SubsequentEventMember2026-04-012026-04-300001868275ceg:CDHIRevolverMemberceg:CalpineMember2026-03-310001868275ceg:NovaPowerCreditAgreementMemberceg:CalpineMember2026-01-310001868275ceg:NovaPowerCreditAgreementMemberceg:CalpineMember2026-01-012026-03-310001868275ceg:NovaPowerCreditAgreementMemberceg:CalpineMember2026-03-310001868275ceg:GreenfieldL.P.LoanFacilityMemberceg:CalpineMember2026-01-310001868275ceg:GreenfieldL.P.LoanFacilityMemberceg:CalpineMember2026-01-012026-03-310001868275ceg:GreenfieldL.P.LoanFacilityMemberceg:CalpineMember2026-03-310001868275ceg:PinOakCreekEnergyCenterCreditAgreementMemberceg:CalpineMember2026-01-310001868275ceg:PinOakCreekEnergyCenterCreditAgreementMemberceg:CalpineMember2026-03-310001868275ceg:CalpineMemberceg:CorporateDebtMemberus-gaap:SecuredDebtMember2026-01-310001868275ceg:CalpineMemberceg:CorporateDebtMemberus-gaap:UnsecuredDebtMember2026-01-310001868275us-gaap:LetterOfCreditMemberceg:CalpineMember2026-01-310001868275ceg:A2029SeniorNotesMemberus-gaap:SeniorNotesMember2026-03-310001868275ceg:A2031SeniorNotesDueFebruaryMemberus-gaap:SeniorNotesMember2026-03-310001868275ceg:A2031SeniorNotesDueMarchMemberus-gaap:SeniorNotesMember2026-03-310001868275us-gaap:SeniorNotesMember2026-03-310001868275ceg:SeniorUnsecuredNotesMemberus-gaap:UnsecuredDebtMember2026-01-310001868275srt:MinimumMemberus-gaap:SeniorNotesMember2026-03-310001868275srt:MaximumMemberus-gaap:SeniorNotesMember2026-03-310001868275us-gaap:SeniorNotesMember2025-12-310001868275srt:MinimumMemberceg:TaxExemptNotesMember2026-03-310001868275srt:MaximumMemberceg:TaxExemptNotesMember2026-03-310001868275ceg:TaxExemptNotesMember2026-03-310001868275ceg:TaxExemptNotesMember2025-12-310001868275srt:MinimumMemberus-gaap:NotesPayableOtherPayablesMember2026-03-310001868275srt:MaximumMemberus-gaap:NotesPayableOtherPayablesMember2026-03-310001868275us-gaap:NotesPayableOtherPayablesMember2026-03-310001868275us-gaap:NotesPayableOtherPayablesMember2025-12-310001868275srt:MinimumMemberceg:NonRecourseVariableRateMember2026-03-310001868275srt:MaximumMemberceg:NonRecourseVariableRateMember2026-03-310001868275ceg:NonRecourseVariableRateMember2026-03-310001868275ceg:NonRecourseVariableRateMember2025-12-310001868275srt:MinimumMemberceg:NonRecourseFixedRateMemberMember2026-03-310001868275srt:MaximumMemberceg:NonRecourseFixedRateMemberMember2026-03-310001868275ceg:NonRecourseFixedRateMemberMember2026-03-310001868275ceg:NonRecourseFixedRateMemberMember2025-12-310001868275ceg:A2028SeniorNotesMember2026-03-310001868275ceg:A2028SeniorNotesMember2026-01-012026-03-310001868275ceg:A2066SeniorNotesMember2026-03-310001868275ceg:A2066SeniorNotesMember2026-01-012026-03-310001868275ceg:A2031SeniorNotesDueFebruaryMember2026-03-310001868275ceg:A2031SeniorNotesDueFebruaryMember2026-01-012026-03-310001868275ceg:A2028FloatingRateSeniorNotesMember2026-01-012026-03-310001868275ceg:PinOakCreekEnergyCenterCreditAgreementMember2026-03-310001868275ceg:PinOakCreekEnergyCenterCreditAgreementMember2026-01-012026-03-310001868275ceg:EnergyEfficiencyProjectFinancingMember2026-03-310001868275ceg:EnergyEfficiencyProjectFinancingMember2026-01-012026-03-310001868275ceg:RPGNonrecourseDebtMember2026-03-310001868275ceg:RPGNonrecourseDebtMember2026-01-012026-03-310001868275ceg:A2031UnsecuredNotesMember2026-03-310001868275ceg:A2031UnsecuredNotesMember2026-01-012026-03-310001868275ceg:A2029UnsecuredNotesMember2026-03-310001868275ceg:A2029UnsecuredNotesMember2026-01-012026-03-310001868275ceg:AntelopeValleyDOELoanMembersrt:MinimumMember2026-03-310001868275ceg:AntelopeValleyDOELoanMembersrt:MaximumMember2026-03-310001868275ceg:AntelopeValleyDOELoanMember2026-01-012026-03-310001868275ceg:GreenfieldL.P.LoanFacilityMember2026-01-012026-03-310001868275ceg:NovaPowerCreditAgreementMember2026-01-012026-03-310001868275ceg:CalpineDevelopmentHoldingsMember2026-01-012026-03-310001868275ceg:ContinentalWindNonrecourseDebtMember2026-03-310001868275ceg:ContinentalWindNonrecourseDebtMember2026-01-012026-03-310001868275ceg:GPCFirstLienSeniorSecuredTermLoanFacilityMember2026-01-012026-03-310001868275ceg:CalpineTermLoanB5Member2026-01-012026-03-310001868275ceg:CalpineSeniorSecuredNotesMember2026-03-310001868275ceg:CalpineSeniorSecuredNotesMember2026-01-012026-03-310001868275ceg:CalpineSeniorUnsecuredNotesMember2026-03-310001868275ceg:CalpineSeniorUnsecuredNotesMember2026-01-012026-03-310001868275ceg:CalpineTermLoanB10Member2026-01-012026-03-310001868275ceg:DOELoanProgramMemberus-gaap:UnsecuredDebtMember2025-11-300001868275ceg:DOELoanProgramMemberus-gaap:UnsecuredDebtMember2025-11-012025-11-300001868275us-gaap:RevolvingCreditFacilityMember2025-12-310001868275us-gaap:RevolvingCreditFacilityMember2026-03-310001868275us-gaap:RevolvingCreditFacilityMember2025-09-012025-09-300001868275us-gaap:RevolvingCreditFacilityMemberceg:DailySimpleSOFRRateMember2025-09-012025-09-300001868275us-gaap:RevolvingCreditFacilityMemberceg:TermSOFRRateMember2025-09-012025-09-300001868275us-gaap:LetterOfCreditMember2026-03-310001868275ceg:DailySimpleSOFRRateMembersrt:MaximumMemberus-gaap:ExternalCreditRatingNonInvestmentGradeMember2026-01-012026-03-310001868275ceg:TermSOFRRateMembersrt:MaximumMemberus-gaap:ExternalCreditRatingNonInvestmentGradeMember2026-01-012026-03-310001868275ceg:AccountsReceivableFacilityMember2024-12-310001868275ceg:AccountsReceivableFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2026-01-012026-03-310001868275ceg:AccountsReceivableFacilityMember2026-02-012026-02-280001868275ceg:AccountsReceivableFacilityMember2026-03-012026-03-310001868275us-gaap:UnsecuredDebtMemberceg:TermLoanDueMay2026Memberus-gaap:SubsequentEventMember2026-04-300001868275ceg:AccountsReceivableFacilityMemberus-gaap:SubsequentEventMember2026-04-012026-04-300001868275ceg:BilateralCreditAgreementsMember2026-03-310001868275ceg:AccountsReceivableFacilityMember2026-03-310001868275ceg:CDHIRevolverMember2026-03-310001868275ceg:LiquidityFacilityMember2026-03-310001868275us-gaap:SecuredDebtMember2026-03-310001868275ceg:BilateralCreditAgreementsMember2025-12-310001868275ceg:AccountsReceivableFacilityMember2025-12-310001868275ceg:LiquidityFacilityMember2025-12-310001868275us-gaap:SecuredDebtMember2025-12-310001868275ceg:OtherCreditFacilityMember2026-03-310001868275ceg:OtherCreditFacilityMember2025-12-310001868275ceg:BilateralCreditAgreementsMember2026-02-012026-02-280001868275ceg:BilateralCreditAgreementsMember2026-02-280001868275ceg:AdditionalThirdUncommittedBilateralFacilityMember2026-02-012026-02-280001868275ceg:BilateralCreditAgreementsMemberus-gaap:UnsecuredDebtMember2026-02-280001868275ceg:BilateralCreditAgreementsMemberus-gaap:UnsecuredDebtMember2026-03-012026-03-310001868275ceg:BilateralCreditAgreementsMember2026-03-012026-03-310001868275ceg:LiquidityFacilityMemberceg:NoAdditionalCollateralPostedMember2026-03-310001868275ceg:LiquidityFacilityMemberceg:NoAdditionalCollateralPostedMember2025-12-310001868275ceg:TermLoanDueMay2026Member2026-01-012026-03-310001868275ceg:TermLoanDueMay2026Memberus-gaap:UnsecuredDebtMember2026-03-310001868275ceg:TermLoanDueMay2026Memberus-gaap:UnsecuredDebtMember2025-12-310001868275ceg:TermLoanDueSeptember2026Member2026-01-012026-03-310001868275ceg:TermLoanDueSeptember2026Memberus-gaap:UnsecuredDebtMember2026-03-310001868275ceg:TermLoanDueSeptember2026Memberus-gaap:UnsecuredDebtMember2025-12-310001868275us-gaap:CarryingReportedAmountFairValueDisclosureMember2026-03-310001868275us-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:FairValueInputsLevel2Member2026-03-310001868275us-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:FairValueInputsLevel3Member2026-03-310001868275us-gaap:EstimateOfFairValueFairValueDisclosureMember2026-03-310001868275us-gaap:CarryingReportedAmountFairValueDisclosureMember2025-12-310001868275us-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:FairValueInputsLevel2Member2025-12-310001868275us-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:FairValueInputsLevel3Member2025-12-310001868275us-gaap:EstimateOfFairValueFairValueDisclosureMember2025-12-310001868275us-gaap:FairValueInputsLevel1Member2026-03-310001868275us-gaap:FairValueInputsLevel2Member2026-03-310001868275us-gaap:FairValueInputsLevel3Member2026-03-310001868275us-gaap:FairValueInputsLevel1Member2025-12-310001868275us-gaap:FairValueInputsLevel2Member2025-12-310001868275us-gaap:FairValueInputsLevel3Member2025-12-310001868275ceg:CashEquivalentsNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel1Member2026-03-310001868275ceg:CashEquivalentsNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel2Member2026-03-310001868275ceg:CashEquivalentsNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel3Member2026-03-310001868275ceg:CashEquivalentsNuclearDecommissioningTrustFundMember2026-03-310001868275ceg:CashEquivalentsNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel1Member2025-12-310001868275ceg:CashEquivalentsNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel2Member2025-12-310001868275ceg:CashEquivalentsNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel3Member2025-12-310001868275ceg:CashEquivalentsNuclearDecommissioningTrustFundMember2025-12-310001868275ceg:EquitySecuritiesNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel1Member2026-03-310001868275ceg:EquitySecuritiesNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel2Member2026-03-310001868275ceg:EquitySecuritiesNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel3Member2026-03-310001868275ceg:EquitySecuritiesNuclearDecommissioningTrustFundMember2026-03-310001868275ceg:EquitySecuritiesNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel1Member2025-12-310001868275ceg:EquitySecuritiesNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel2Member2025-12-310001868275ceg:EquitySecuritiesNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel3Member2025-12-310001868275ceg:EquitySecuritiesNuclearDecommissioningTrustFundMember2025-12-310001868275us-gaap:FixedIncomeSecuritiesMemberus-gaap:FairValueInputsLevel1Member2026-03-310001868275us-gaap:FixedIncomeSecuritiesMemberus-gaap:FairValueInputsLevel2Member2026-03-310001868275us-gaap:FixedIncomeSecuritiesMemberus-gaap:FairValueInputsLevel3Member2026-03-310001868275us-gaap:FixedIncomeSecuritiesMember2026-03-310001868275us-gaap:FixedIncomeSecuritiesMemberus-gaap:FairValueInputsLevel1Member2025-12-310001868275us-gaap:FixedIncomeSecuritiesMemberus-gaap:FairValueInputsLevel2Member2025-12-310001868275us-gaap:FixedIncomeSecuritiesMemberus-gaap:FairValueInputsLevel3Member2025-12-310001868275us-gaap:FixedIncomeSecuritiesMember2025-12-310001868275ceg:PrivateCreditNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel1Member2026-03-310001868275ceg:PrivateCreditNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel2Member2026-03-310001868275ceg:PrivateCreditNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel3Member2026-03-310001868275ceg:PrivateCreditNuclearDecommissioningTrustFundMember2026-03-310001868275ceg:PrivateCreditNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel1Member2025-12-310001868275ceg:PrivateCreditNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel2Member2025-12-310001868275ceg:PrivateCreditNuclearDecommissioningTrustFundMemberus-gaap:FairValueInputsLevel3Member2025-12-310001868275ceg:PrivateCreditNuclearDecommissioningTrustFundMember2025-12-310001868275us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2026-03-310001868275us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2025-12-310001868275us-gaap:FairValueInputsLevel12And3Member2026-03-310001868275us-gaap:FairValueInputsLevel12And3Member2025-12-310001868275us-gaap:CashAndCashEquivalentsMembersrt:ParentCompanyMember2026-03-310001868275us-gaap:CashAndCashEquivalentsMembersrt:ParentCompanyMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:CashAndCashEquivalentsMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberus-gaap:CashAndCashEquivalentsMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:RestrictedcashMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:RestrictedcashMember2025-12-310001868275us-gaap:CashMembersrt:ParentCompanyMember2026-03-310001868275us-gaap:CashMembersrt:ParentCompanyMember2025-12-310001868275ceg:NuclearDecommissioningTrustFundInvestmentsMember2026-03-310001868275ceg:NuclearDecommissioningTrustFundInvestmentsMember2025-12-310001868275ceg:PrivateCreditMember2026-03-310001868275us-gaap:PrivateEquityFundsMember2026-03-310001868275us-gaap:RealEstateFundsMember2026-03-310001868275ceg:NuclearDecommissioningTrustFundInvestmentsMemberus-gaap:FairValueInputsLevel3Member2025-12-310001868275us-gaap:DerivativeMemberus-gaap:FairValueInputsLevel3Member2025-12-310001868275ceg:RabbiTrustInvestmentsMemberus-gaap:FairValueInputsLevel3Member2025-12-310001868275ceg:NuclearDecommissioningTrustFundInvestmentsMemberus-gaap:FairValueInputsLevel3Member2026-01-012026-03-310001868275us-gaap:DerivativeMemberus-gaap:FairValueInputsLevel3Member2026-01-012026-03-310001868275ceg:RabbiTrustInvestmentsMemberus-gaap:FairValueInputsLevel3Member2026-01-012026-03-310001868275us-gaap:FairValueInputsLevel3Member2026-01-012026-03-310001868275ceg:NuclearDecommissioningTrustFundInvestmentsMemberus-gaap:FairValueInputsLevel3Member2026-03-310001868275us-gaap:DerivativeMemberus-gaap:FairValueInputsLevel3Member2026-03-310001868275ceg:RabbiTrustInvestmentsMemberus-gaap:FairValueInputsLevel3Member2026-03-310001868275ceg:NuclearDecommissioningTrustFundInvestmentsMemberus-gaap:FairValueInputsLevel3Member2024-12-310001868275us-gaap:DerivativeMemberus-gaap:FairValueInputsLevel3Member2024-12-310001868275ceg:RabbiTrustInvestmentsMemberus-gaap:FairValueInputsLevel3Member2024-12-310001868275us-gaap:FairValueInputsLevel3Member2024-12-310001868275ceg:NuclearDecommissioningTrustFundInvestmentsMemberus-gaap:FairValueInputsLevel3Member2025-01-012025-03-310001868275us-gaap:DerivativeMemberus-gaap:FairValueInputsLevel3Member2025-01-012025-03-310001868275ceg:RabbiTrustInvestmentsMemberus-gaap:FairValueInputsLevel3Member2025-01-012025-03-310001868275us-gaap:FairValueInputsLevel3Member2025-01-012025-03-310001868275ceg:NuclearDecommissioningTrustFundInvestmentsMemberus-gaap:FairValueInputsLevel3Member2025-03-310001868275us-gaap:DerivativeMemberus-gaap:FairValueInputsLevel3Member2025-03-310001868275ceg:RabbiTrustInvestmentsMemberus-gaap:FairValueInputsLevel3Member2025-03-310001868275us-gaap:FairValueInputsLevel3Member2025-03-310001868275ceg:OperatingRevenueMemberus-gaap:FairValueInputsLevel3Member2026-01-012026-03-310001868275ceg:OperatingRevenueMemberus-gaap:FairValueInputsLevel3Member2025-01-012025-03-310001868275ceg:PurchasedPowerAndFuelMemberus-gaap:FairValueInputsLevel3Member2026-01-012026-03-310001868275ceg:PurchasedPowerAndFuelMemberus-gaap:FairValueInputsLevel3Member2025-01-012025-03-310001868275ceg:OtherNetMemberus-gaap:FairValueInputsLevel3Member2026-01-012026-03-310001868275ceg:OtherNetMemberus-gaap:FairValueInputsLevel3Member2025-01-012025-03-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Member2026-03-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Member2025-12-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Memberus-gaap:IncomeApproachValuationTechniqueMembersrt:MinimumMember2026-03-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Memberus-gaap:IncomeApproachValuationTechniqueMembersrt:MaximumMember2026-03-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Memberus-gaap:IncomeApproachValuationTechniqueMembersrt:ArithmeticAverageMember2026-03-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Memberus-gaap:IncomeApproachValuationTechniqueMembersrt:MinimumMember2025-12-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Memberus-gaap:IncomeApproachValuationTechniqueMembersrt:MaximumMember2025-12-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Memberus-gaap:IncomeApproachValuationTechniqueMembersrt:ArithmeticAverageMember2025-12-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Memberceg:OptionModelValuationTechniqueMembersrt:MinimumMember2026-03-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Memberceg:OptionModelValuationTechniqueMembersrt:MaximumMember2026-03-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Memberceg:OptionModelValuationTechniqueMembersrt:ArithmeticAverageMember2026-03-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Memberceg:OptionModelValuationTechniqueMembersrt:MinimumMember2025-12-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Memberceg:OptionModelValuationTechniqueMembersrt:MaximumMember2025-12-310001868275ceg:EconomicHedgesMemberus-gaap:FairValueInputsLevel3Memberceg:OptionModelValuationTechniqueMembersrt:ArithmeticAverageMember2025-12-310001868275us-gaap:FinancialStandbyLetterOfCreditMember2026-03-310001868275us-gaap:SuretyBondMember2026-03-310001868275us-gaap:GuaranteeOfIndebtednessOfOthersMember2026-03-310001868275ceg:FirstPriorityLienPowerAndNaturalGasAgreementsMember2026-03-310001868275us-gaap:AccountsPayableAndAccruedLiabilitiesMember2025-12-310001868275us-gaap:AccountsPayableAndAccruedLiabilitiesMember2026-03-310001868275us-gaap:OtherLiabilitiesMember2025-12-310001868275us-gaap:OtherLiabilitiesMember2026-03-310001868275ceg:CapitalAllocationPlanMember2026-01-012026-03-310001868275ceg:CapitalAllocationPlanMemberus-gaap:SubsequentEventMember2026-05-110001868275ceg:CapitalAllocationPlanMember2025-01-012025-03-310001868275ceg:CapitalAllocationPlanMemberus-gaap:SubsequentEventMember2026-04-012026-05-110001868275ceg:CapitalAllocationPlanMember2025-03-310001868275ceg:CapitalAllocationPlanMember2025-04-012025-09-300001868275us-gaap:AccumulatedGainLossNetCashFlowHedgeParentMember2025-12-310001868275us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2025-12-310001868275us-gaap:AccumulatedTranslationAdjustmentMember2025-12-310001868275us-gaap:AccumulatedGainLossNetCashFlowHedgeParentMember2026-01-012026-03-310001868275us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2026-01-012026-03-310001868275us-gaap:AccumulatedTranslationAdjustmentMember2026-01-012026-03-310001868275us-gaap:AccumulatedOtherComprehensiveIncomeMember2026-01-012026-03-310001868275us-gaap:AccumulatedGainLossNetCashFlowHedgeParentMember2026-03-310001868275us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2026-03-310001868275us-gaap:AccumulatedTranslationAdjustmentMember2026-03-310001868275us-gaap:AccumulatedGainLossNetCashFlowHedgeParentMember2024-12-310001868275us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2024-12-310001868275us-gaap:AccumulatedTranslationAdjustmentMember2024-12-310001868275us-gaap:AccumulatedGainLossNetCashFlowHedgeParentMember2025-01-012025-03-310001868275us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2025-01-012025-03-310001868275us-gaap:AccumulatedTranslationAdjustmentMember2025-01-012025-03-310001868275us-gaap:AccumulatedGainLossNetCashFlowHedgeParentMember2025-03-310001868275us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2025-03-310001868275us-gaap:AccumulatedTranslationAdjustmentMember2025-03-310001868275us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMember2026-01-012026-03-310001868275us-gaap:AccumulatedDefinedBenefitPlansAdjustmentNetUnamortizedGainLossMember2025-01-012025-03-310001868275us-gaap:VariableInterestEntityPrimaryBeneficiaryMember2026-03-310001868275us-gaap:VariableInterestEntityPrimaryBeneficiaryMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:CRPMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:CRPMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:AntelopeValleyMember2025-12-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:AntelopeValleyMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:NERMember2026-03-310001868275ceg:ConstellationEnergyGenerationLLCMemberceg:NERMember2025-12-310001868275ceg:CommercialAgreementVIEMemberus-gaap:VariableInterestEntityNotPrimaryBeneficiaryMember2026-03-310001868275ceg:EquityInvestmentVIEMemberus-gaap:VariableInterestEntityNotPrimaryBeneficiaryMember2026-03-310001868275us-gaap:VariableInterestEntityNotPrimaryBeneficiaryMember2026-03-310001868275ceg:CommercialAgreementVIEMemberus-gaap:VariableInterestEntityNotPrimaryBeneficiaryMember2025-12-310001868275ceg:EquityInvestmentVIEMemberus-gaap:VariableInterestEntityNotPrimaryBeneficiaryMember2025-12-310001868275us-gaap:VariableInterestEntityNotPrimaryBeneficiaryMember2025-12-310001868275ceg:UnamortizedEnergyContractsMember2026-01-012026-03-310001868275ceg:UnamortizedEnergyContractsMember2025-01-012025-03-310001868275us-gaap:NonrelatedPartyMember2026-03-310001868275us-gaap:NonrelatedPartyMember2025-12-310001868275ceg:EmployeeBenefitTrustsAndInvestmentsMember2026-03-310001868275ceg:EmployeeBenefitTrustsAndInvestmentsMember2025-12-310001868275ceg:EquityInvestmentsWithReadilyDeterminableFairValuesMember2026-03-310001868275ceg:EquityInvestmentsWithReadilyDeterminableFairValuesMember2025-12-310001868275ceg:EquityInvestmentsWithoutReadilyDeterminableFairValuesMember2026-03-310001868275ceg:EquityInvestmentsWithoutReadilyDeterminableFairValuesMember2025-12-310001868275ceg:OtherAvailableForSaleDebtSecurityInvestmentsMember2026-03-310001868275ceg:OtherAvailableForSaleDebtSecurityInvestmentsMember2025-12-31

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q


☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2026


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission
File Number

Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number

IRS Employer Identification Number

001-41137

CONSTELLATION ENERGY CORPORATION

87-1210716

(a Pennsylvania corporation)

1310 Point Street

Baltimore, Maryland 21231-3380

(833) 883-0162

333-85496

CONSTELLATION ENERGY GENERATION, LLC

23-3064219

(a Pennsylvania limited liability company)

200 Energy Way

Kennett Square, Pennsylvania 19348-2473

(833) 883-0162

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

CONSTELLATION ENERGY CORPORATION:

Common Stock, without par value

CEG

The Nasdaq Stock Market LLC

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.

Constellation Energy Corporation

Yes

☐

Constellation Energy Generation, LLC

Yes

☐

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

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

Constellation Energy Corporation

Large Accelerated Filer

Accelerated Filer

☐

Non-accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

Constellation Energy Generation, LLC

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

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

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

The number of shares outstanding of each registrant’s common stock as of April 30, 2026 was as follows:


Constellation Energy Corporation Common Stock, without par value			361,190,063
Constellation Energy Generation, LLC			Not applicable

TABLE OF CONTENTS


		Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS		1
FILING FORMAT		4
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION		4
AVAILABLE INFORMATION		4
PART I	FINANCIAL INFORMATION	4
ITEM 1.	FINANCIAL STATEMENTS	4
	Constellation Energy Corporation
	Consolidated Statements of Operations and Comprehensive Income	5
	Consolidated Statements of Cash Flows	6
	Consolidated Balance Sheets	7
	Consolidated Statements of Changes in Equity	8
	Constellation Energy Generation, LLC
	Consolidated Statements of Operations and Comprehensive Income	9
	Consolidated Statements of Cash Flows	10
	Consolidated Balance Sheets	11
	Consolidated Statements of Changes in Equity	12
	Combined Notes to Consolidated Financial Statements
	1. Basis of Presentation	13
	2. Mergers, Acquisitions, and Dispositions	13
	3. Regulatory Matters	17
	4. Revenue from Contracts with Customers	18
	5. Segment Information	19
	6. Government Assistance	21
	7. Accounts Receivable	22
	8. Property, Plant, and Equipment	23
	9. Asset Retirement Obligations	24
	10. Income Taxes	25
	11. Retirement Benefits	27
	12. Derivative Financial Instruments	27
	13. Debt and Credit Agreements	32
	14. Fair Value of Financial Assets and Liabilities	38
	15. Commitments and Contingencies	42

	16. Shareholders' Equity	44
	17. Variable Interest Entities	45
	18. Supplemental Financial Information	47

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Constellation Energy Corporation and Related Entities
CEG Parent						Constellation Energy Corporation
Constellation						Constellation Energy Generation, LLC
Registrants						CEG Parent and Constellation, collectively
Antelope Valley						Antelope Valley Solar Ranch One
Calpine						Calpine Corporation
Calvert Cliffs						Calvert Cliffs nuclear generating station
CCFC						Calpine Construction Finance Company, L.P.
CDHI						Calpine Development Holdings, LLC

Continental Wind						Continental Wind LLC

Crane						Crane Clean Energy Center (formerly known as Three Mile Island Unit 1)
CRP						Constellation Renewables Partners, LLC
FitzPatrick						James A. FitzPatrick nuclear generating station

GPC						Geysers Power Company, LLC
Greenfield L.P.						Greenfield Energy Centre L.P.
LaSalle						LaSalle nuclear generating station
Limerick						Limerick nuclear generating station
NER						NewEnergy Receivables LLC
NMP						Nine Mile Point nuclear generating station
Nova Power						Nova Power, LLC
Pin Oak Creek						Pin Oak Creek Energy Center
RPG						Renewable Power Generation, LLC

STP						South Texas Project nuclear generating station
West Medway II						West Medway Generating Station II



Other Terms and Abbreviations
AB						Assembly Bill



AEP Texas						American Electric Power Texas
AESO						Alberta Electric Systems Operator

AOCI						Accumulated Other Comprehensive Income (Loss)

ARC						Asset Retirement Cost
ARO						Asset Retirement Obligation














CAISO						California ISO










CenterPoint						CenterPoint Energy Houston Electric, LLC










CMC						Carbon Mitigation Credit
CO2						Carbon Dioxide
CODM						Chief Operating Decision Maker








ComEd						Commonwealth Edison Company
CORRA						Canadian Overnight Repo Rate Average
CWIP						Construction Work In Progress


DOE						United States Department of Energy


DOJ						United States Department of Justice





EGU						Electric Generating Units



EFOF						Equivalent Forced Outage Factor


ERCOT						Electric Reliability Council of Texas
ERISA						Employee Retirement Income Security Act of 1974, as amended







Exchange Act						Securities Exchange Act of 1934, as amended

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Exelon						Exelon Corporation



FERC						Federal Energy Regulatory Commission
Former ComEd Units						Braidwood, Byron, Dresden, LaSalle and Quad Cities nuclear generating units
Former PECO Units						Limerick, Peach Bottom, and Salem nuclear generating units
FRCC						Florida Reliability Coordinating Council

GAAP						Generally Accepted Accounting Principles in the United States
GDP						Gross Domestic Product
Geysers Assets						Geothermal power plant assets acquired through Calpine, including steam extraction and gathering assets
GHG						Greenhouse Gas

GW						Gigawatt
GWh						Gigawatt hour
Heat Rate						A measure of the amount of fuel required to produce a unit of power


ICE						Intercontinental Exchange
IPA						Illinois Power Agency
IRA						Inflation Reduction Act of 2022

IRS						Internal Revenue Service
ISO						Independent System Operator
ISO-NE						ISO New England Inc.
ITC						Investment Tax Credit











MISO						Midcontinent Independent System Operator, Inc.
MMBtu						Million British thermal units
Moody's						Moody’s Investors Service, Inc.



MW						Megawatt
MWh						Megawatt hour



NASDAQ						Nasdaq Stock Market, LLC
NAV						Net Asset Value
NDT						Nuclear Decommissioning Trust


NERC						North American Electric Reliability Corporation
NGX						Natural Gas Exchange, Inc.



Non-Regulatory Agreement Units						Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting

NOx						Nitrogen oxide


NPNS						Normal Purchase Normal Sale scope exception
NRC						Nuclear Regulatory Commission


NYISO						New York ISO
NYMEX						New York Mercantile Exchange


OCI						Other Comprehensive Income
OIESO						Ontario Independent Electricity System Operator
OPEB						Other Postretirement Employee Benefits





PECO						PECO Energy Company
Pension Protection Act						Pension Protection Act of 2006
PG&E						Pacific Gas and Electric Company
PJM						PJM Interconnection, LLC
PPA						Power Purchase Agreement
PP&E						Property, Plant, and Equipment

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
PSDAR						Post-shutdown Decommissioning Activities Report
PSEG						Public Service Enterprise Group Incorporated
PTC						Production Tax Credit







Regulatory Agreement Units						Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting (includes the Former ComEd Units, the Former PECO Units and STP)






RNF						Operating Revenues Net of Purchased Power and Fuel Expense





RPM						Reliability Pricing Model
RTO						Regional Transmission Organization
S&P						S&P Global Ratings, a Standard & Poor’s Financial Services LLC business
SB						Senate Bill

SEC						United States Securities and Exchange Commission
SERC						SERC Reliability Corporation (formerly Southeast Electric Reliability Council)

SNF						Spent Nuclear Fuel
SO2						Sulfur dioxide

SOFR						Secured Overnight Financing Rate




SPP						Southwest Power Pool


STPNOC						STP Nuclear Operating Company

TMA						Tax Matters Agreement




TWh						Terawatt-hour

U.S. Treasury						U.S. Department of the Treasury
UEC						Unamortized Energy Contract



VIE						Variable Interest Entity
WECC						Western Electric Coordinating Council
ZEC						Zero Emission Credit

Table of Contents

FILING FORMAT

This combined Form 10-Q is being filed separately by Constellation Energy Corporation and Constellation Energy Generation, LLC, (the Registrants). Information contained herein relating to any individual Registrant is filed by the Registrant on its own behalf. Neither Registrant makes any representation as to information relating to the other Registrant.

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

This report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding the acquisition of Calpine Corporation, the pro forma combined company and its operations, strategies and plans, enhancements to investment-grade credit profile, synergies, opportunities and anticipated future performance and capital structure, and expected accretion to earnings per share and free cash flow. Information adjusted for the acquisition should not be considered a forecast of future results.

Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. The factors that could cause actual results to differ materially from the forward-looking statements made by us include those factors discussed herein, as well as the items discussed in (1) the Registrants' combined 2025 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18 — Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 15 — Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.

Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this report. Neither Registrant undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this report.

AVAILABLE INFORMATION

The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that we file electronically with the SEC. We file our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports with the SEC. In addition, as soon as reasonably practicable after such materials are furnished to the SEC, we make copies of these documents available to the public free of charge through our website at www.ConstellationEnergy.com. Information contained on our website shall not be deemed incorporated into, or to be a part of, this Report.

PART I. FINANCIAL INFORMATION


ITEM 1. FINANCIAL STATEMENTS

Table of Contents

Constellation Energy Corporation and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income

(Unaudited)


	Three Months Ended March 31,
(In millions, except per share data)		2026		2025
Operating revenues		$	11,122	$	6,788



Operating expenses
Purchased power and fuel		6,352		4,384

Operating and maintenance		1,780		1,545

Depreciation and amortization		443		248
Taxes other than income taxes		229		160
Total operating expenses		8,804		6,337

Gain (loss) on sales of assets		14		—

Operating income (loss)		2,332		451
Other income and (deductions)
Interest expense, net		(253)		(146)

Other, net		46		(154)
Total other income and (deductions)		(207)		(300)
Income (loss) before income taxes		2,125		151
Income tax (benefit) expense		530		22
Equity in income (losses) of unconsolidated affiliates		8		—
Net income (loss)		1,603		129
Net income (loss) attributable to noncontrolling interests		13		11
Net income (loss) attributable to common shareholders		$	1,590	$	118
Comprehensive income (loss), net of income taxes
Net income (loss)		$	1,603	$	129
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost		(1)		—
Actuarial loss reclassified to periodic cost		28		17
Pension and non-pension postretirement benefit plan valuation adjustment		(25)		(34)
Unrealized gain (loss) on cash flow hedges		1		2
Unrealized gain (loss) on foreign currency translation		(3)		8
Other comprehensive income (loss), net of income taxes		—		(7)
Comprehensive income (loss)		1,603		122
Comprehensive income (loss) attributable to noncontrolling interests		13		11
Comprehensive income (loss) attributable to common shareholders		$	1,590	$	111

Average shares of common stock outstanding:
Basic		354		313
Assumed exercise and/or distributions of stock-based awards		—		1
Diluted		354		314

Earnings per average common share
Basic		$	4.49	$	0.38
Diluted		$	4.49	$	0.38

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Corporation and Subsidiary Companies

Consolidated Statements of Cash Flows

(Unaudited)


	Three Months Ended March 31,
(In millions)	2026		2025
Cash flows from operating activities
Net income (loss)	$	1,603	$	129
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities
Depreciation, amortization, and accretion, including nuclear fuel and contract amortization	1,202		640


Deferred income taxes and amortization of ITCs	440		(98)
Net fair value changes related to derivatives	(1,040)		356
Net realized and unrealized (gains) losses on NDT funds	(17)		(44)
Net realized and unrealized (gains) losses on equity investments	27		268
Other non-cash operating activities	(199)		47
Changes in assets and liabilities:
Accounts receivable	323		(15)

Inventories	106		98
Accounts payable and accrued expenses	(1,377)		(290)
Option premiums received (paid), net	(15)		26
Collateral received (posted), net	249		(486)
Income taxes	103		120
Pension and non-pension postretirement benefit contributions	(191)		(174)
Other assets and liabilities	(789)		(470)
Net cash flows provided by (used in) operating activities	425		107
Cash flows from investing activities
Capital expenditures	(1,275)		(806)
Proceeds from NDT fund sales	2,504		2,084
Investment in NDT funds	(2,572)		(2,152)
Acquisition of Calpine, net of cash and restricted cash acquired	(2,537)		—



Other investing activities	148		(12)
Net cash flows provided by (used in) investing activities	(3,732)		(886)
Cash flows from financing activities
Change in short-term borrowings	1,957		—
Proceeds from short-term borrowings with maturities greater than 90 days	3,000		—
Repayments of short-term borrowings with maturities greater than 90 days	(1,500)		—
Issuance of long-term debt	2,770		—
Retirement of long-term debt	(5,254)		(57)
Dividends paid on common stock	(155)		(122)

Other financing activities	(88)		(229)
Net cash flows provided by (used in) financing activities	730		(408)
Increase (decrease) in cash, restricted cash, and cash equivalents	(2,577)		(1,187)
Cash, restricted cash, and cash equivalents at beginning of period	3,748		3,129
Cash, restricted cash, and cash equivalents at end of period	$	1,171	$	1,942

Supplemental disclosure of non-cash investing and financing activities
Common stock issued for acquisition of Calpine	$	17,507	$	—

Exchange of Calpine senior notes for Constellation senior notes	2,290		—

Decrease in PP&E related to ARO update	(889)		(6)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Corporation and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	March 31, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	800	$	3,641
Restricted cash and cash equivalents	371		107
Accounts receivable, net	4,414		4,266


Derivative assets	1,795		945


Inventories, net	2,582		1,736




Renewable energy credits	1,038		789
Assets held for sale	5,735		126
Other	1,274		509
Total current assets	18,009		12,119
Property, plant, and equipment (net of accumulated depreciation and amortization of $19,524 and $19,072, respectively)	40,769		22,474
Deferred debits and other assets

Nuclear decommissioning trust funds	19,366		19,336

Goodwill	11,527		420
Derivative assets	2,113		450





Other	5,127		2,450
Total deferred debits and other assets	38,133		22,656
Total assets(a)	$	96,911	$	57,249

LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	5,102	$	1,650
Long-term debt due within one year	370		92

Accounts payable and accrued expenses	4,449		4,294



Derivative liabilities	810		467

Renewable energy credit obligation	1,193		1,075


Other	1,291		366
Total current liabilities	13,215		7,944
Long-term debt	16,994		7,250


Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs	8,199		3,544
Asset retirement obligations	12,433		13,193
Pension and non-pension postretirement benefit obligations	1,835		1,977



Payables related to Regulatory Agreement Units	5,389		5,334
Derivative liabilities	518		414


Other	4,508		2,740
Total deferred credits and other liabilities	32,882		27,202
Total liabilities(a)	63,091		42,396
Commitments and contingencies (Note 15)

Shareholders' equity
Common stock (No par value, 1,000 shares authorized, 362 and 312 shares outstanding, respectively)	28,574		11,043
Retained earnings (deficit)	7,334		5,899
Accumulated other comprehensive income (loss), net	(2,425)		(2,425)
Total shareholders' equity	33,483		14,517
Noncontrolling interests	337		336
Total equity	33,820		14,853
Total liabilities and shareholders' equity	$	96,911	$	57,249

__________

(a)Our consolidated assets include $4,609 million and $4,551 million at March 31, 2026 and December 31, 2025, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $2,381 million and $914 million at March 31, 2026 and December 31, 2025, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 17 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Corporation and Subsidiary Companies

Consolidated Statements of Changes in Equity

(Unaudited)


	Three Months Ended March 31, 2026
	Shareholders' Equity
(In millions, shares in thousands)	Issued Shares	Common Stock		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss), net		Noncontrolling Interests		Total Equity
Balance, December 31, 2025	312,355	$	11,043	$	5,899	$	(2,425)	$	336	$	14,853
Net Income (loss)	—	—		1,590		—		13		1,603
Employee incentive plans	628	24		—		—		—		24
Changes in equity of noncontrolling interests	—	—		—		—		(12)		(12)
Common stock dividends ($0.4265/common share)	—	—		(155)		—		—		(155)

Common stock issued to acquire Calpine	49,376	17,507		—		—		—		17,507

Balance, March 31, 2026	362,359	$	28,574	$	7,334	$	(2,425)	$	337	$	33,820


	Three Months Ended March 31, 2025
	Shareholders' Equity
(In millions, shares in thousands)	Issued Shares	Common Stock		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss), net		Noncontrolling Interests		Total Equity
Balance, December 31, 2024	312,838	$	11,402	$	4,066	$	(2,302)	$	373	$	13,539
Net Income (loss)	—	—		118		—		11		129
Employee incentive plans	547	(49)		—		—		—		(49)
Changes in equity of noncontrolling interests	—	—		—		—		(6)		(6)
Common stock dividends ($0.3878/common share)	—	—		(122)		—		—		(122)

Capped call option contracts	—	(150)		—		—		—		(150)
Other comprehensive income (loss), net of income taxes	—	—		—		(7)		—		(7)
Balance, March 31, 2025	313,385	$	11,203	$	4,062	$	(2,309)	$	378	$	13,334

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income

(Unaudited)


	Three Months Ended March 31,
(In millions)		2026		2025
Operating revenues		$	11,122	$	6,788



Operating expenses
Purchased power and fuel		6,352		4,384

Operating and maintenance		1,780		1,545

Depreciation and amortization		443		248
Taxes other than income taxes		229		160
Total operating expenses		8,804		6,337

Gain (loss) on sales of assets		14		—


Operating income (loss)		2,332		451
Other income and (deductions)
Interest expense, net		(253)		(146)

Other, net		46		(154)
Total other income and (deductions)		(207)		(300)
Income (loss) before income taxes		2,125		151
Income tax (benefit) expense		530		22
Equity in income (losses) of unconsolidated affiliates		8		—
Net income (loss)		1,603		129
Net income (loss) attributable to noncontrolling interests		13		11
Net income (loss) attributable to membership interest		$	1,590	$	118
Comprehensive income (loss), net of income taxes
Net income (loss)		$	1,603	$	129
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost		(1)		—
Actuarial loss reclassified to periodic cost		28		17
Pension and non-pension postretirement benefit plan valuation adjustment		(25)		(34)
Unrealized gain (loss) on cash flow hedges		1		2
Unrealized gain (loss) on foreign currency translation		(3)		8
Other comprehensive income (loss), net of income taxes		—		(7)
Comprehensive income (loss)		1,603		122
Comprehensive income (loss) attributable to noncontrolling interests		13		11
Comprehensive income (loss) attributable to membership interest		$	1,590	$	111

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Statements of Cash Flows

(Unaudited)


	Three Months Ended March 31,
(In millions)	2026		2025
Cash flows from operating activities
Net income (loss)	$	1,603	$	129
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities
Depreciation, amortization, and accretion, including nuclear fuel and contract amortization	1,202		640


Deferred income taxes and amortization of ITCs	440		(98)
Net fair value changes related to derivatives	(1,040)		356
Net realized and unrealized (gains) losses on NDT funds	(17)		(44)
Net realized and unrealized (gains) losses on equity investments	27		268
Other non-cash operating activities	(229)		24
Changes in assets and liabilities:
Accounts receivable	330		(15)
Receivables from and payables to affiliates, net	(272)		(259)
Inventories	106		98
Accounts payable and accrued expenses	(1,386)		(301)
Option premiums received (paid), net	(15)		26
Collateral received (posted), net	249		(486)
Income taxes	103		120
Pension and non-pension postretirement benefit contributions	(191)		(174)
Other assets and liabilities	(527)		(257)
Net cash flows provided by (used in) operating activities	383		27
Cash flows from investing activities
Capital expenditures	(1,275)		(806)
Proceeds from NDT fund sales	2,504		2,084
Investment in NDT funds	(2,572)		(2,152)


Acquisition of Calpine, net of cash and restricted cash acquired	(2,537)		—

Other investing activities	150		(12)
Net cash flows provided by (used in) investing activities	(3,730)		(886)
Cash flows from financing activities
Change in short-term borrowings	1,957		—
Proceeds from short-term borrowings with maturities greater than 90 days	3,000		—
Repayments of short-term borrowings with maturities greater than 90 days	(1,500)		—
Issuance of long-term debt	2,770		—
Retirement of long-term debt	(5,254)		(57)
Distributions to member	(155)		(272)

Other financing activities	(55)		(5)
Net cash flows provided by (used in) financing activities	763		(334)
Increase (decrease) in cash, restricted cash, and cash equivalents	(2,584)		(1,193)
Cash, restricted cash, and cash equivalents at beginning of period	3,720		3,115
Cash, restricted cash, and cash equivalents at end of period	$	1,136	$	1,922

Supplemental disclosure of non-cash investing and financing activities

Acquisition of Calpine	$	17,503	$	—
Exchange of Calpine senior notes for Constellation senior notes	2,290		—
Decrease in PP&E related to ARO update	(889)		(6)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	March 31, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	785	$	3,641
Restricted cash and cash equivalents	351		79
Accounts receivable, net	4,392		4,251


Derivative assets	1,795		945



Inventories, net	2,582		1,736




Renewable energy credits	1,038		789
Assets held for sale	5,735		126
Other	1,282		508
Total current assets	17,960		12,075
Property, plant, and equipment (net of accumulated depreciation and amortization of $19,524 and $19,072, respectively)	40,769		22,474
Deferred debits and other assets

Nuclear decommissioning trust funds	19,366		19,336

Goodwill	11,527		420
Derivative assets	2,113		450





Other	5,120		2,443
Total deferred debits and other assets	38,126		22,649
Total assets(a)	$	96,855	$	57,198

LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	5,102	$	1,650
Long-term debt due within one year	370		92

Accounts payable and accrued expenses	4,324		4,033
Payables to affiliates	102		365



Derivative liabilities	810		467

Renewable energy credit obligation	1,193		1,075

Other	1,289		358
Total current liabilities	13,190		8,040
Long-term debt	16,994		7,250


Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs	8,199		3,544
Asset retirement obligations	12,433		13,193
Pension and non-pension postretirement benefit obligations	1,835		1,977


Payables related to Regulatory Agreement Units	5,389		5,334
Derivative liabilities	518		414


Other	4,465		2,583
Total deferred credits and other liabilities	32,839		27,045
Total liabilities(a)	63,023		42,335
Commitments and contingencies (Note 15)

Equity
Member’s equity
Membership interest	27,677		10,144
Undistributed earnings (deficit)	8,243		6,808
Accumulated other comprehensive income (loss), net	(2,425)		(2,425)
Total member’s equity	33,495		14,527
Noncontrolling interests	337		336
Total equity	33,832		14,863
Total liabilities and equity	$	96,855	$	57,198

__________

(a)Our consolidated assets include $4,609 million and $4,551 million as of March 31, 2026 and December 31, 2025, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $2,381 million and $914 million as of March 31, 2026 and December 31, 2025, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 17 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Statements of Changes in Equity
(Unaudited)


	Three Months Ended March 31, 2026
	Member's Equity
(In millions)	Membership Interest		Undistributed Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss), net		Noncontrolling Interests		Total Equity
Balance, December 31, 2025	$	10,144	$	6,808	$	(2,425)	$	336	$	14,863
Net Income (loss)	—		1,590		—		13		1,603
Changes in equity of noncontrolling interests	—		—		—		(12)		(12)
Distributions to member	—		(155)		—		—		(155)
Contribution from member	30		—		—		—		30
Acquisition of Calpine	17,503		—		—		—		17,503

Balance, March 31, 2026	$	27,677	$	8,243	$	(2,425)	$	337	$	33,832


	Three Months Ended March 31, 2025
	Member's Equity
(In millions)	Membership Interest		Undistributed Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss), net		Noncontrolling Interests		Total Equity
Balance, December 31, 2024	$	10,538	$	4,974	$	(2,302)	$	373	$	13,583
Net Income (loss)	—		118		—		11		129
Changes in equity of noncontrolling interests	—		—		—		(6)		(6)
Distributions to member	(150)		(122)		—		—		(272)
Other comprehensive income (loss), net of income taxes	—		—		(7)		—		(7)
Balance, March 31, 2025	$	10,388	$	4,970	$	(2,309)	$	378	$	13,427

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

1. Basis of Presentation

Description of Business

We are the nation's largest producer of clean and reliable energy and a leading supplier of energy products and services. Our fleet of generation assets includes nuclear, natural gas, oil, hydroelectric, geothermal, wind, and solar facilities. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, public sector, and residential customers in markets across multiple geographic regions. We have six reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, Other Power Regions, and Calpine.

Basis of Presentation

The accompanying Consolidated Financial Statements as of March 31, 2026 and for the three months ended March 31, 2026 and 2025 are unaudited but, in our opinion, include all adjustments that are considered necessary for a fair statement of the results for the periods reported herein in accordance with GAAP. All adjustments are of a normal, recurring nature, unless otherwise disclosed. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated in consolidation. Our December 31, 2025 Consolidated Balance Sheet was derived from audited financial statements. The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2026. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. Certain prior period amounts have been reclassified to conform to the presentation in the current period. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation.

Summary of Significant Accounting Policies

See Note 1 — Basis of Presentation of our 2025 Form 10-K for additional information on significant accounting policies.

2. Mergers, Acquisitions, and Dispositions

Acquisition of Calpine Corporation

On January 7, 2026 (the “Acquisition Date”), we acquired all of the outstanding equity interests in Calpine in a cash and stock transaction. Pursuant to the Merger Agreement and related transaction steps, Calpine was converted into a limited liability company, Calpine LLC, and became a wholly owned subsidiary of Constellation.

This acquisition is complementary to, and aligns strategically with, our existing business operations and provides both increased scale and meaningful market diversification. The merger couples the largest producer of clean, emissions-free energy with the reliable, dispatchable natural gas assets of Calpine, and also creates the nation’s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that enable us to meet growing demand with a broad array of energy and sustainability products. The addition of Calpine strengthens our essential role in providing clean, reliable energy as the nation seeks to transition to a more sustainable future, and will improve our position to pursue investments in new and existing technologies to meet growing demand.

The merger consideration consisted of 50 million newly issued shares of our common stock, no par value, and approximately $4.5 billion in cash. In connection with the merger, certain of the newly issued shares will be subject to a lock-up period, which expires on June 30, 2026, for 50% of the shares and on June 30, 2027, for the remaining 50%.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

Calpine operates a competitive retail electric supplier platform serving approximately 62 TWhs of load annually. Calpine also owns and operates a generation fleet of natural gas, oil, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, after considering divestitures required by certain regulatory approvals for the transaction. The final regulatory clearance for the merger was the DOJ resolution, which requires the divestiture of five generating assets located in PJM, one in ERCOT, and Calpine's minority interest in the Gregory Power Plant, also in ERCOT. The DOJ resolution requires us to enter into definitive agreement(s) to divest these assets within 240 days of closing the acquisition, by September 4, 2026.

The transaction was accounted for as a business combination using the acquisition method of accounting where we are considered the acquirer for accounting purposes. We recognized the identifiable assets acquired and liabilities assumed at their estimated fair values as of January 7, 2026, with any excess of the consideration transferred over the fair value of net identifiable assets recognized as goodwill.

In January 2026, we completed the divestiture of Calpine's minority ownership interest in the Gregory Power Plant, as required under the terms of the DOJ resolution. In March 2026, we entered into an agreement with LS Power Equity Advisors, LLC ("LS Power") whereby we will sell five generation assets in PJM to LS Power, which comprise approximately 4.4 GW of predominantly natural gas-fired generation capacity located in Delaware and Pennsylvania, for aggregate consideration of $5.0 billion before closing adjustments. Closing of the sale is subject to receipt of applicable regulatory approvals, including review by the DOJ and FERC, and other customary closing conditions. We are taking steps to divest the ERCOT plant, the last asset sale required to satisfy our regulatory commitments under the merger. Certain of the generation assets being sold are currently secured under project financing arrangements, see Note 13 — Debt and Credit Agreements for additional information.

Consideration Transferred

The following table summarizes the components of the total merger consideration transferred. There was no contingent consideration associated with the acquisition.


Fair value of CEG Parent common stock issued(a)	$	17,603
Cash consideration(b)	4,342
Fair value of common stock subject to vesting period attributable to post-combination expense(c)	(96)
Effective settlement of preexisting relationships	(14)
Total merger consideration	$	21,835

__________

(a)Represents the fair value of approximately 50 million shares of CEG Parent common stock issued in connection with the acquisition, calculated using CEG Parent’s closing stock price of $354.58 on January 6, 2026, the last trading day prior to the Acquisition Date. The fair value of the stock consideration is based on an observable market price and represents a Level 1 fair value measurement.

(b)Represents cash paid to Calpine shareholders in connection with the acquisition. The amount reflects the $4.5 billion base cash consideration per the Merger Agreement, reduced by certain adjustments based on contractual terms also specified in the Merger Agreement.

(c)Certain CEG Parent common stock issued to Calpine employees in exchange for their equity interests is subject to a vesting period of up to 26 months and has been excluded from merger consideration. These amounts will be recognized as stock-based compensation expense over the applicable vesting period in accordance with authoritative guidance.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

Purchase Price Allocation

The following table presents the preliminary allocation of the total merger consideration to the identifiable assets acquired and liabilities assumed as of the Acquisition Date. The allocation is preliminary and subject to revision during the measurement period, which will not exceed one year from the Acquisition Date. Adjustments to provisional amounts will be recognized in the reporting period in which they are identified, with a corresponding adjustment to goodwill.


Assets acquired:
Cash and cash equivalents	$	1,540
Restricted cash and cash equivalents	261
Accounts receivable	761
Derivative assets	2,140
Inventories	989
Assets held for sale(a)	5,603
Property, plant, and equipment	18,481
Renewable energy credits	180
Unamortized energy contracts(b)	2,133
Other assets	700
Total assets acquired	$	32,788

Liabilities assumed:
Accounts payable and accrued expenses	$	1,601
Long-term debt (including amounts due within one year)(c)	12,551
Derivative liabilities	644
Renewable energy credit obligation	258
Deferred income taxes and unamortized ITCs	4,083
Asset retirement obligations	350
Unamortized energy contracts(b)	1,815
Other liabilities	758
Total liabilities assumed	22,060
Net identifiable assets acquired	10,728
Goodwill(d)	11,107
Total consideration transferred	$	21,835

(a) Assets Held for Sale. Reflects the Acquisition Date fair value, less costs to sell, for the six generating assets required to be divested. Depreciation and amortization of these assets ceased upon classification as held for sale. No impairment has been recognized subsequent to initial classification. The following table presents the carrying amounts of the major classes of assets and liabilities classified as held for sale as of the Acquisition Date:


Assets held for sale:
Property, plant and equipment	$	5,454
Inventories	136
Other assets	13
Total assets held for sale	$	5,603

Liabilities associated with assets held for sale:
Asset retirement obligations	$	16
Other liabilities	82
Total liabilities associated with assets held for sale	$	98

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

(b) Unamortized Energy Contracts. The following table summarizes the classification and amounts of UECs in the Consolidated Balance Sheets as of the Acquisition Date:


Other current assets	$	517
Other deferred debits and other assets	1,616
Other current liabilities	367
Other deferred credits and other liabilities	1,448

(c) Long-term Debt (including amounts due within one year). We assumed total debt of $12,551 million at estimated fair value as of the Acquisition Date, comprising $279 million classified as Long-term debt due within one year and $12,272 million classified as Long-term debt, in the Consolidated Balance Sheets. See Note 13 — Debt and Credit Agreements for additional information.

(d) Goodwill. Represents the excess of the purchase price over the estimated fair value of the net assets acquired. Goodwill recognized primarily reflects the expected benefits from increased scale and meaningful market diversification, complementary generation and retail capabilities, and an enhanced ability to meet growing demand with a broader array of energy and sustainability products, to the extent such benefits are not separately recognizable as identifiable intangible assets. Goodwill will be assigned to the reporting units expected to benefit from the acquisition. The assignment of goodwill to the reporting units has not been completed as of the date of these financial statements due to the preliminary nature of the purchase price allocation. The goodwill recognized in connection with the acquisition is not expected to be deductible for income tax purposes.

Valuation of Significant Assets and Liabilities

The preliminary fair values assigned to the assets acquired and liabilities assumed were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows; discount rates reflecting the risks inherent in the future cash flows; and future market prices, among others. These estimates and assumptions were applied to the valuation of significant acquired assets and assumed liabilities, including property, plant and equipment, assets held for sale, and unamortized energy contracts, and required assessments of current and projected market conditions and operating strategies. Forecasting future cash flows requires assumptions regarding, among other things, forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of the assets, and judgments are also made to determine the expected useful lives assigned to each class of assets acquired and the duration of liabilities assumed.

Other Key Accounting Impacts & Judgments

Identifiable intangible assets acquired and liabilities assumed in connection with the acquisition include customer relationships, trade names, and energy contracts, recorded at estimated fair value. The weighted average amortization periods reflect weighted average useful lives of 15 years for customer relationships, five years for trade names, and six years for energy contracts.

We also recognized the fair value of acquired commodity and interest rate derivatives and related hedging relationships as of the Acquisition Date; related gains or losses subsequent to acquisition will be recognized in earnings consistent with our accounting policies. For additional information on derivative instruments, see Note 12 — Derivative Financial Instruments.

The amounts recognized for property, plant and equipment, identifiable intangible assets and liabilities (including customer relationships, trade names, and unamortized energy contracts) and their useful lives, lease assets and liabilities, asset retirement and environmental obligations, contingencies, and income taxes (including deferred taxes) are provisional and subject to revision during the measurement period.

Acquisition-related costs (e.g., advisory, legal, valuation, and other professional fees) are expensed as incurred and reflected within Operating and maintenance expenses in the Consolidated Statements of Operations and Comprehensive Income. These costs, which are not included in the consideration transferred, were not material for the three months ended March 31, 2026.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

Unaudited Pro Forma Results

The following unaudited pro forma financial information for the three months ended March 31, 2026 and 2025 assumes that the acquisition occurred on January 1, 2025. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the acquisition been completed on January 1, 2025. The unaudited pro forma financial information is not indicative of the future results of operations, which may differ materially from the pro forma financial information presented here.


	Three Months Ended March 31,
Unaudited pro forma financial information	2026		2025
Operating revenues	$	11,352	$	9,321
Net income(a)	1,590		147

__________

(a)Reflects Net income attributable to common shareholders for CEG Parent and Net income attributable to membership interest for Constellation.

The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, the effects of the acquisition on tax expense (benefit), and other acquisition accounting adjustments.

As discussed in Note 5 — Segment Information, Calpine is now presented as a reportable segment, and RNF is the segment performance metric, a component of which includes revenue. From the Acquisition Date through March 31, 2026, Operating revenues attributable to Calpine were $3,136 million. However, as a result of the commencement of integration activities for certain functions and the consolidation of financing activities (see Note 13 — Debt and Credit Agreements), it is impracticable to determine Calpine’s earnings since the Acquisition Date.

3. Regulatory Matters

As discussed in Note 3 — Regulatory Matters of our 2025 Form 10-K, we are involved in various regulatory and legislative proceedings. The following discusses developments in 2026 and updates to the 2025 Form 10-K.

Capacity Interconnection Rights for Crane Clean Energy Center

In 2024, we announced the restart of Three Mile Island Unit 1, renamed as the Crane Clean Energy Center. The restart is supported by a 20-year PPA with Microsoft to purchase the output generated from the renewed plant. The restart of the plant and delivery of electricity under the PPA is subject to certain regulatory approvals, including the NRC comprehensive safety and environmental review, as well as permits from relevant state and local agencies.

PJM's Phase I System Impact Study for Crane identified contingent transmission upgrades that would need to be completed for Crane to be fully deliverable to the grid, some of which suggested projected in-service dates extending as late as December 2030.

In March 2026, we filed a waiver request with FERC to allow the transfer of capacity interconnection rights (CIRs) from Eddystone to Crane with the aim of reducing the number of contingent upgrades that would need to be completed prior to Crane being fully deliverable to the grid. Eddystone Units 3 and 4 were previously announced as having a planned retirement date of May 31, 2025, but have been required to continue operating as energy-only resources under DOE emergency orders issued in 2025 and 2026 for grid reliability. Transferring the Eddystone CIRs to Crane will not affect PJM's ability to operate and dispatch Eddystone for reliability in compliance with the DOE's orders. We have requested that FERC grant the requested waiver no later than June 1, 2026.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers

4. Revenue from Contracts with Customers

We recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that we expect to be entitled to in exchange for those goods or services. Our primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and sustainable solutions.

See Note 4 — Revenue from Contracts with Customers of our 2025 Form 10-K for additional information regarding the performance obligations, revenue recognition, and payment terms associated with these sources of revenue.

Transaction Price Allocated to Remaining Performance Obligations

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of March 31, 2026. This disclosure only includes components of contracts for which consideration is fixed and determinable. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes derivatives and certain power and gas sales contracts which contain variable volumes and/or variable pricing.


	2026		2027		2028		2029		2030		2031 and thereafter		Total
Remaining performance obligations	$	1,342	$	1,757	$	1,494	$	1,415	$	889	$	5,137	$	12,034

Revenue Disaggregation

We disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The following tables disaggregate the revenue recognized from contracts with customers between power revenues, capacity revenues, natural gas revenues, and other revenues. Power revenues and capacity revenues are further disaggregated by ISO/RTO and/or geographic location, which include PJM, MISO, ERCOT, NYISO, ISO-NE, West (which includes operations in CAISO, Arizona and Oregon), SERC/SPP, and International Power (which includes operations in the United Kingdom and Canada).


Three Months Ended March 31, 2026	Power and Power-related Revenues(a)		Capacity Revenues(b)		Other Revenues		Total
PJM	$	3,330	$	130	$	—	$	3,460
MISO	252		6		—		258
ERCOT	360		99		—		459
NYISO	745		13		—		758
ISO-NE	1,014		4		—		1,018
West	168		160		—		328
SERC/SPP	59		4		—		63
International Power	109		—		—		109
Total Power revenues	6,037		416		—		6,453
Gas revenues(c)	—		—		943		943
Other revenues(d)	—		—		145		145
Total revenue from contracts with customers	6,037		416		1,088		7,541
Other revenue sources(e)	—		—		3,581		3,581
Total Operating revenues	$	6,037	$	416	$	4,669	$	11,122

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers


Three Months Ended March 31, 2025	Power and Power-related Revenues(a)		Capacity Revenues(b)		Other Revenues		Total
PJM	$	2,698	$	8	$	—	$	2,706
MISO	214		—		—		214
ERCOT	301		—		—		301
NYISO	675		—		—		675
ISO-NE	1,109		—		—		1,109
West	146		1		—		147
SERC/SPP	35		3		—		38
International Power	48		—		—		48
Total Power revenues	5,226		12		—		5,238
Gas revenues(c)	—		—		782		782
Other revenues(d)	—		—		86		86
Total revenue from contracts with customers	5,226		12		868		6,106
Other revenue sources(e)	—		—		682		682
Total Operating revenues	$	5,226	$	12	$	1,550	$	6,788

__________

(a)Represents power and power-related revenues, including state-sponsored program revenues, ancillary revenues, and revenues from bundled contracts with customers.

(b)Represents revenues from regulated capacity auctions as well as bilateral capacity revenues recognized at negotiated contract prices.

(c)Represents natural gas sales and other gas-related revenues.

(d)Other revenues primarily includes the sales of other energy-related products and sustainable solutions.

(e)Other revenue sources primarily includes revenues accounted for as derivatives, leases, and amortization of certain intangible assets and liabilities related to commodity contracts recorded at fair value from acquisitions.

5. Segment Information

Operating segments are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources. We have six reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, all other power regions referred to collectively as “Other Power Regions,” and Calpine.

Following the acquisition of Calpine on January 7, 2026, Calpine's operations are being reported as a new reportable segment given the results of its operations will be reviewed by the CODM separately from our historical reporting segments.

With the exception of Calpine, the basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of our six reportable segments are as follows:

•Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina.

•Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.

•New York represents operations within NYISO.

•ERCOT represents operations within Electric Reliability Council of Texas that covers a majority of the state of Texas.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 5 — Segment Information

•Other Power Regions:

•New England represents operations within ISO-NE.

•South represents operations in FRCC, MISO’s Southern Region, and the remaining portions of SERC not included within MISO or PJM.

•West represents operations in WECC, which includes CAISO.

•Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO.

•Calpine represents operations acquired through the merger with Calpine on January 7, 2026, which are located throughout the country, including CAISO, ERCOT, PJM, ISO-NE, NYISO, MISO, SERC, Arizona, Oregon, and Canada.

Constellation's CEO is considered the CODM and evaluates the performance of our electric business activities and allocates resources based on segment RNF, primarily through review of budget-to-actual variance analyses. RNF is Operating revenues net of Purchased power and fuel expenses. We believe this is a useful measurement of operational performance, although it is not a presentation defined under GAAP and may not be comparable to other companies’ presentations nor deemed more useful than the GAAP information provided elsewhere in this report. In our evaluation of operating segments, we noted the CODM reviews a variety of performance and profitability measures at a consolidated level with a primary focus on RNF reporting at the geographic regional level, with the exception of Calpine which is reviewed on a standalone basis. Our operating revenues include all sales to third parties as well as government assistance. Purchased power and fuel expenses are considered the most significant segment expense. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for our owned generation and fuel costs associated with tolling agreements. The results of our other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments nor included in the reportable segment amounts. These activities include wholesale and retail sales of natural gas, with the exception of Calpine's natural gas sales which are included in the Calpine segment, energy-related sales in the United Kingdom, as well as sales of other energy-related products and sustainable solutions that are not significant to our overall results of operations. Further, our unrealized gains and losses on economic hedging activities and our amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the reportable segment amounts. The CODM does not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

The following tables, which relate directly to our Consolidated Statements of Operations and Comprehensive Income, provide the reconciliation of operating revenues, purchased power and fuel expenses, and RNF for our reportable segments for the three months ended March 31, 2026 and 2025.


























Three Months Ended March 31, 2026	Total Operating revenues		Total Purchased power and fuel expenses		Total RNF
Mid-Atlantic	$	1,847	$	(1,035)	$	812
Midwest	1,732		(878)		854
New York	569		(160)		409
ERCOT	370		(161)		209
Other Power Regions	1,487		(1,220)		267
Calpine	2,395		(1,269)		1,126
Total Reportable Segments	8,400		(4,723)		3,677
Other(a)	2,722		(1,629)		1,093
Total Consolidated Results	$	11,122	$	(6,352)	$	4,770

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 5 — Segment Information


Three Months Ended March 31, 2025	Total Operating revenues		Total Purchased power and fuel expenses		Total RNF
Mid-Atlantic	$	1,665	$	(856)	$	809
Midwest	1,404		(554)		850
New York	562		(161)		401
ERCOT	398		(184)		214
Other Power Regions	1,556		(1,362)		194

Total Reportable Segments	5,585		(3,117)		2,468
Other(a)	1,203		(1,267)		(64)
Total Consolidated Results	$	6,788	$	(4,384)	$	2,404

__________

(a)Represents activities not allocated to a segment. See text above for a description of included activities. Operating revenues include unrealized gains of $1,315 million and losses of $287 million for the three months ended March 31, 2026 and 2025, respectively. Purchased power and fuel expenses include unrealized losses of $254 million and $34 million for the three months ended March 31, 2026 and 2025, respectively.

6. Government Assistance

Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. See Note 1 — Basis of Presentation and Note 6 — Government Assistance of our 2025 Form 10-K for additional information on nuclear PTCs.

For the three months ended March 31, 2026 and 2025, we did not record a material nuclear PTC benefit as the estimate of full year gross receipts exceeded the phase-out for annual gross receipts per MWh for most units. As of March 31, 2026 and December 31, 2025, our Consolidated Balance Sheets reflect approximately $125 million and $120 million, respectively, of nuclear PTCs within Other deferred debits and other assets. For the three months ended March 31, 2026, we did not utilize any estimated nuclear PTCs as a credit against our current federal income taxes payable. For the year ended December 31, 2025, we recognized a reduction to Accounts payable and accrued expenses in our Consolidated Balance Sheets of $375 million for estimated nuclear PTCs that we have utilized as a credit against our current federal income taxes payable.

Many of the state-sponsored programs providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. As of March 31, 2026 and December 31, 2025, we have recognized approximately $740 million and $1,190 million, respectively, of estimated payables within Other deferred credits and other liabilities, Accounts payable and accrued expenses or as offsets to Accounts receivable, net in our Consolidated Balance Sheets associated with programs requiring refunds or pass through of the nuclear PTC. In general, we expect to remit refunds or pass-throughs of state-sponsored program compensation related to nuclear PTCs in the year following the filing of the related tax return. During the three months ended March 31, 2026, we refunded or offset against outstanding receivables approximately $450 million associated with state-sponsored program compensation relating to the nuclear PTCs recorded in 2024. During the three months ended March 31, 2026, we recognized a reduction to net operating revenue of approximately $285 million associated with these programs in our Consolidated Statements of Operations and Comprehensive Income, compared to an increase to net operating revenue (pre-tax) of approximately $110 million for the three months ended March 31, 2025.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 7 — Accounts Receivable

7. Accounts Receivable

The following table provides additional information on the disaggregation of customer and other accounts receivable:


	Accounts receivable, net
March 31, 2026	CEG Parent		Constellation
Customer accounts receivable (net of allowance for credit losses of $157 for CEG Parent and Constellation)	$	3,960	$	3,960
Other accounts receivable (net of allowance for credit losses of $— for CEG Parent and Constellation)	454		432
Total	$	4,414	$	4,392


December 31, 2025
Customer accounts receivable (net of allowance for credit losses of $158 for CEG Parent and Constellation)	$	3,577	$	3,577
Other accounts receivable (net of allowance for credit losses of $9 for CEG Parent and Constellation)	689		674
Total	$	4,266	$	4,251

Allowance for Credit Losses on Accounts Receivable

The following table presents the rollforward of allowance for credit losses on customer accounts receivable from January 1, 2026 to March 31, 2026.






Balance as of January 1, 2026	$	158
Current period provision for expected credit losses	15
Write-offs, net of recoveries(a)	(16)

Balance as of March 31, 2026	$	157

__________

(a)Recoveries were not material.

The allowance for credit losses on other accounts receivable was not material as of the balance sheet dates, therefore, a rollforward is not presented.

Unbilled Customer Revenue

We recorded $1,465 million and $1,305 million of unbilled customer revenues in Accounts receivable, net in the Consolidated Balance Sheets as of March 31, 2026 and December 31, 2025, respectively.

Calpine Accounts Receivable Sales Program

Following the acquisition of Calpine on January 7, 2026, the Company has assumed Calpine's Accounts Receivable Sales Program (Calpine AR Facility). The Calpine AR Facility was established by Calpine in December 2016 and was last renewed in November 2025 with a current expiration of November 2026. The Calpine AR Facility is a receivables purchase agreement between Calpine Energy Solutions, LLC and Calpine Receivables, LLC, a wholly-owned subsidiary that is accounted for as an unconsolidated VIE, along with an additional purchase and sale agreement between Calpine Receivables, LLC, and unaffiliated financial institutions, the combination of which allow for the revolving sale of up to $500 million in certain trade accounts receivables of Calpine Energy Solutions, LLC to third parties at a nominal discount.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 7 — Accounts Receivable

Receivables sold under the Calpine AR Facility are accounted for as sales and excluded from Accounts receivable, net in the Consolidated Balance Sheets and reflected as Cash provided by operating activities in the Consolidated Statements of Cash Flows. Any portion of the purchase price for the sold receivables which is not paid in cash is recorded as a short-term note receivable within Accounts receivable, net, which was not material as of March 31, 2026. Our risk of loss following the transfer of accounts receivable is limited to the note receivable outstanding. Payment of the note receivable is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred.

The Company has guaranteed the performance of Calpine Energy Solutions, LLC to Calpine Receivables, LLC under the Calpine AR Facility, see Note 15 — Commitments and Contingencies for additional information. Additionally, see Note 17 — Variable Interest Entities for additional information on Calpine Receivables, LLC and its status as an unconsolidated VIE.

There was $564 million in gross accounts receivable outstanding that were sold at a nominal discount under the Calpine AR Facility as of March 31, 2026 and the $500 million facility amount was fully utilized. The following table summarizes certain activity for the period under the Calpine AR Facility:


	Three Months Ended March 31, 2026
Aggregate receivables sold during the period	$	1,205
Proceeds collected on sold receivables	1,126

Other Sales of Customer Accounts Receivables

We are required, under supplier tariffs, to sell customer receivables to certain utility companies at a nominal discount. The total gross receivables sold were $1,244 million and $1,147 million for the three months ended March 31, 2026 and 2025, respectively.

8. Property, Plant, and Equipment

The following table presents a summary of property, plant, and equipment by asset category as of March 31, 2026 and December 31, 2025:


Asset Category	March 31, 2026		December 31, 2025
Electric(a)	$	49,844	$	33,253
Nuclear fuel	6,712		6,298
CWIP(a)	3,737		1,995

Total property, plant, and equipment	60,293		41,546
Less: accumulated depreciation	19,524		19,072
Property, plant, and equipment, net(b)	$	40,769	$	22,474

__________

(a)Includes Electric and CWIP assets acquired as a result of the Calpine acquisition of $17,247 million and $1,234 million, respectively.

(b)Excludes assets held for sale related to acquisition of Calpine. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

The estimated useful lives of our generating facilities are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected energy market conditions. As a result of the acquisition of Calpine, we added a fleet of natural gas, oil, geothermal, battery storage and solar assets. There were no material changes in the estimated useful lives of our combined oil and gas, battery storage, wind and solar facilities as a result. Geothermal facility depreciation provisions are based on an estimated useful life through 2066. For additional information about the useful lives of our generating facilities and depreciation provisions see Note 8 — Property, Plant, and Equipment of our 2025 Form 10-K.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 9 — Asset Retirement Obligations

9. Asset Retirement Obligations

Nuclear Decommissioning Asset Retirement Obligations

We have a legal obligation to decommission our nuclear power plants following the permanent cessation of operations. See Note 10 — Asset Retirement Obligations of our 2025 Form 10-K for additional information regarding AROs and the financial statement impact of changes in estimates.

The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from December 31, 2025 to March 31, 2026:


Balance as of December 31, 2025	$	12,908

Accretion expense	165
Net decrease due to changes in, and timing of, estimated future cash flows	(1,277)
Costs incurred related to decommissioning plants	(4)

Balance as of March 31, 2026	$	11,792

During the three months ended March 31, 2026, the net $1,277 million decrease in the ARO for the changes in, and timing of, estimated future cash flows was driven primarily by changes in assumed retirement dates for various plants, including Calvert Cliffs, Fitzpatrick, Limerick, and Nine Mile Point.

The 2026 ARO update resulted in a decrease of $285 million in Operating and maintenance expense for the three months ended March 31, 2026 in the Consolidated Statements of Operations and Comprehensive income.

NDT Funds

We had NDT funds totaling $19,494 million and $19,396 million as of March 31, 2026 and December 31, 2025, respectively. The current portions of the NDT funds, which are included in Other current assets in our Consolidated Balance Sheets, were not material as of March 31, 2026 and December 31, 2025. See Note 18 — Supplemental Financial Information for additional information on activities of the NDT funds.

Accounting Implications of the Regulatory Agreement Units

See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations of our 2025 Form 10-K for additional information on the Regulatory Agreement Units.

The following table presents our noncurrent payables to ComEd, PECO, CenterPoint, and AEP Texas reflected as Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets as of March 31, 2026 and December 31, 2025:


	March 31, 2026		December 31, 2025
ComEd	$	4,297	$	4,313
PECO	533		442
CenterPoint	416		430
AEP Texas	143		149
Payables related to Regulatory Agreement Units	$	5,389	$	5,334

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts for radiological decommissioning of the facility at the end of its life.

We filed our annual decommissioning funding status report with the NRC for our shutdown units, and any units within five years of shutdown in March 2026. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2025 for all units included in the report. See Note 10 — Asset Retirement Obligations of our 2025 Form 10-K for additional information.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 9 — Asset Retirement Obligations

Non-Nuclear Asset Retirement Obligations

We have AROs for plant closure costs associated with our natural gas, oil, battery storage, and renewable generating facilities. The obligations include asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations, disposal of hazardous materials, plug and abandonment of wells, and other decommissioning-related activities. See Note 1 — Basis of Presentation of our 2025 Form 10-K for additional information on the accounting policy for AROs.

The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from December 31, 2025 to March 31, 2026:


Balance as of December 31, 2025	$	317
Acquisition of Calpine(a)	350

Accretion expense	9
Costs incurred related to decommissioning plants	(1)
Balance as of March 31, 2026	$	675

__________

(a)Reflects our decommissioning obligations for Calpine plants acquired on January 7, 2026, which are recorded at estimated fair value. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Many of the facilities acquired from Calpine do not have AROs given the absence of legal requirements to perform retirement related activities.

10. Income Taxes

Rate Reconciliation

The effective income tax rate varies from the U.S. federal statutory rate principally due to the following:


	Three Months Ended March 31,
	2026				2025
U.S. federal statutory income tax	21.0	%	$	446	21.0	%	$	32
Increase (decrease) due to:
State income taxes, net of federal income tax benefit(a)	3.4		73		(0.7)		(1)
Foreign tax effects	—		—		0.7		1
Tax credits
PTC	(0.2)		(4)		(1.3)		(2)
Amortization of ITC, including deferred taxes on basis differences	(0.2)		(5)		(2.0)		(3)
Other	(0.2)		(5)		(2.0)		(3)
Nontaxable or nondeductible items
Share-based payment awards	(0.7)		(14)		(25.2)		(38)
Excess officers compensation	0.1		3		4.6		7
Other	0.8		17		0.9		1
Other adjustments
Qualified NDT fund income and losses	0.9		19		18.6		28
Effective income tax(b)	24.9	%	$	530	14.6	%	$	22

__________

(a)In 2026, state taxes in California, Massachusetts, and New York made up the majority (greater than 50%) of the tax effect in this category. In 2025, state taxes in Illinois, Maryland, Massachusetts, California, Pennsylvania, and New Jersey made up the majority (greater than 50%) of the tax effect in this category.

(b)Amounts may not recalculate due to rounding.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 10 — Income Taxes

Other Tax Matters

Tax Matters Agreement

In connection with the separation, we entered into a TMA with Exelon. The TMA governs the respective rights, responsibilities, and obligations between us and Exelon after the separation with respect to tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns.

Responsibility and Indemnification for Taxes. As a former subsidiary of Exelon, we have joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods in which we were included in joint federal and state filings. However, the TMA specifies the portion of this tax liability for which we will bear contractual responsibility, and we and Exelon agreed to indemnify each other against any amounts for which such indemnified party is not responsible. Specifically, we will be liable for taxes due and payable in connection with tax returns that we are required to file. We will also be liable for our share of certain taxes required to be paid by Exelon with respect to taxable years or periods (or portions thereof) ending on or prior to the separation to the extent that we would have been responsible for such taxes under the Exelon tax sharing agreement then existing. As of March 31, 2026 and December 31, 2025, respectively, our Consolidated Balance Sheets reflect $32 million and $43 million in Other deferred credits and other liabilities, for tax liabilities where we maintain contractual responsibility to Exelon.

Tax Refunds and Attributes. The TMA provides for the allocation of certain pre-closing tax attributes between us and Exelon. Tax attributes will be allocated in accordance with the principles set forth in the existing Exelon tax sharing agreement, unless otherwise required by law. Under the TMA, we will be entitled to refunds for taxes for which we are responsible. In addition, it is expected that Exelon will have tax attributes that may be used to offset Exelon’s future tax liabilities. A significant portion of such attributes were generated by our business. In February 2024, we executed an amendment to the TMA that modified the timing of Exelon's payment of amounts due to us. In March 2026, we adjusted our receivable under the TMA as a result of IRS Notice 2026-7, as discussed below. As of March 31, 2026 and December 31, 2025, respectively, we had $58 million and $175 million in Accounts receivable, net and $373 million and $21 million in Other deferred debits and other assets for the reclassified tax attributes expected to be utilized by Exelon after separation in accordance with the terms of the TMA.

IRS Notice 2026-7. In February 2026, the IRS issued Notice 2026‑7 (the “Notice”), which provides guidance on the implementation of the corporate alternative minimum tax (CAMT). The Notice permits taxpayers to deduct repair and maintenance costs under tax law principles in determining adjusted financial statement income and applies retroactively to previously filed tax returns. As a result of this Notice, Exelon amended its 2023 and 2024 tax returns to reflect less CAMT and thus lower utilization of previously refunded tax attributes.

We received a demand letter from Exelon in February 2026, and as a result, in March 2026 we remitted $235 million to Exelon under the TMA related to prior periods. We increased our receivable for the $235 million in the first quarter of 2026, as reflected above, as we expect Exelon to pay us as it utilizes these tax attributes in future periods.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 11 — Retirement Benefits

11. Retirement Benefits

Components of Net Periodic Benefit (Credits) Costs

See Note 1 — Basis of Presentation of our 2025 Form 10-K for additional information on where we report the service cost and other non-service cost (credit) components for all plans.

The following tables present the components of our net periodic benefit (credit) cost for the three months ended March 31, 2026 and 2025. The amounts below are shown prior to capitalization and co-owner allocations, the effects of which were not material for any of the periods presented.
















	Pension Benefits				OPEB				Total Pension Benefits and OPEB
Three Months Ended March 31,	2026		2025		2026		2025		2026		2025
Components of net periodic benefit (credit) cost:
Service cost	$	22	$	21	$	5	$	4	$	27	$	25
Non-service components of pension benefits & OPEB (credit) cost:
Interest cost	99		102		20		19		119		121
Expected return on assets	(119)		(122)		(8)		(8)		(127)		(130)
Amortization of:
Prior service (credit) cost	—		—		(1)		(2)		(1)		(2)
Actuarial (gain) loss	38		26		(1)		(2)		37		24

Non-service components of pension benefits & OPEB (credit) cost	18		6		10		7		28		13
Net periodic benefit (credit) cost	$	40	$	27	$	15	$	11	$	55	$	38

12. Derivative Financial Instruments

We use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations.

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments, including NPNS, are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. All derivative instruments, excluding NPNS, are recorded at fair value through earnings. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle, and revenue or expense is recognized in earnings as the underlying physical commodity is delivered.

Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, our energy-related economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.

Our use of cash collateral is generally unrestricted unless we were downgraded below investment grade. As our senior unsecured debt rating is currently rated at BBB+ and Baa1 by S&P and Moody's, respectively, it would take a three-notch downgrade by S&P or Moody's for our rating to go below investment grade.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 12 — Derivative Financial Instruments

Commodity Price Risk

We employ established policies and procedures to manage our risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and energy-related products. We believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged. Beginning in 2024, our existing nuclear fleet is eligible for a nuclear PTC, an important tool in managing commodity price risk for each nuclear unit not already receiving state support. The nuclear PTC provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year. See Note 6 — Government Assistance for additional information.

In locations and periods where our load serving activities do not naturally offset existing generation portfolio risk, remaining commodity price exposure is managed through portfolio hedging activities. Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation. During this prompt three-year period, we seek to mitigate the price risk associated with our load serving contracts, non-nuclear generation, and any residual price risk for our nuclear generation that the nuclear PTC and state programs may not fully mitigate. We also enter into transactions that further optimize the economic benefits of our overall portfolio.

To the extent the amount of energy we produce or procure differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in the prices of electricity, natural gas, and other commodities. We use a variety of derivative and non-derivative instruments to manage the commodity price risk of our electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. We are also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 12 — Derivative Financial Instruments

The following tables provide a summary of the commodity derivative fair value balances recorded as of March 31, 2026 and December 31, 2025:


March 31, 2026	Economic Hedges		Collateral(a)		Netting(a)		Total
Derivative assets (current)	$	13,711	$	453	$	(12,436)	$	1,728
Derivative assets (noncurrent)	8,352		306		(6,573)		2,085
Total derivative assets	22,063		759		(19,009)		3,813
Derivative liabilities (current)	(13,807)		564		12,436		(807)
Derivative liabilities (noncurrent)	(7,446)		360		6,573		(513)
Total derivative liabilities	(21,253)		924		19,009		(1,320)
Total derivative net assets (liabilities)	$	810	$	1,683	$	—	$	2,493

December 31, 2025
Derivative assets (current)	$	7,349	$	375	$	(6,791)	$	933
Derivative assets (noncurrent)	5,030		272		(4,853)		449
Total derivative assets	12,379		647		(11,644)		1,382
Derivative liabilities (current)	(7,642)		386		6,791		(465)
Derivative liabilities (noncurrent)	(5,585)		319		4,853		(413)
Total derivative liabilities	(13,227)		705		11,644		(878)
Total derivative net assets (liabilities)	$	(848)	$	1,352	$	—	$	504

_________

(a)We net all available amounts allowed in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral.

The following table summarizes the net buy/(sell) notional position of commodity derivative transactions, excluding our NPNS derivatives that are not recorded at fair value, as of March 31, 2026 and December 31, 2025:

Total Net Position (In Millions)

Commodity Type

March 31, 2026

December 31, 2025

Unit of Measure

Electricity(a)

(638)

(260)

MWh

Natural Gas(a)

1,576

MMBtu

Emissions

(28)

(35)

Short Ton

_________

(a)The increase of net notional position at March 31, 2026 compared to December 31, 2025 is primarily driven by derivatives acquired from Calpine. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

Economic Hedges (Commodity Price Risk)

For the three months ended March 31, 2026 and 2025, we recognized the following net pre-tax commodity unrealized gains (losses), which are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.


	Three Months Ended March 31,
Income Statement Location		2026		2025
Operating revenues		$	1,311	$	(287)
Purchased power and fuel		(252)		(37)
Total		$	1,059	$	(324)

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 12 — Derivative Financial Instruments

Interest Rate Risk

We utilize interest rate swaps to manage our interest rate exposure, which are treated as economic hedges. The notional amounts for interest rate swaps were approximately $4.6 billion and $1.4 billion as of March 31, 2026 and December 31, 2025, respectively.

The derivative assets and liabilities as of March 31, 2026 and December 31, 2025 and the gains and losses associated with management of interest rate risk for the three months ended March 31, 2026 and 2025 were not material. The gains and losses associated with management of interest rate risk are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.

Credit Risk

We would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts as of the reporting date.

For commodity derivatives, we enter into enabling agreements that allow for payment netting with our counterparties, which reduces our exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to right of offset language in the enabling agreement, our credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and other risk management criteria. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with us, as specified in each enabling agreement. Our credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on the credit exposure for derivative instruments, inclusive of payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of March 31, 2026. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, NPNS contracts, forward values on non-derivative contracts and exposure through RTOs, ISOs, as well as commodity exchanges. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties.


Rating as of March 31, 2026	Total Exposure Before Credit Collateral		Credit Collateral(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,979	$	41	$	1,938	1	$	457
Non-investment grade	86		18		68		—	—
No external ratings
Internally rated — investment grade	151		5		146		—	—
Internally rated — non-investment grade	319		58		261		—	—
Total	$	2,535	$	122	$	2,413	1	$	457

__________

(a)As of March 31, 2026, credit collateral held from counterparties where we had credit exposure included $36 million of cash and $86 million of letters of credit.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 12 — Derivative Financial Instruments


Net Credit Exposure by Type of Counterparty	As of March 31, 2026
Investor-owned utilities, marketers, power producers	$	1,218
Financial Institutions	599
Energy cooperatives and municipalities	223
Other	373
Total	$	2,413

Credit-Risk-Related Contingent Features

As part of the normal course of business, we routinely enter into physically and financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of our derivative instruments contain provisions that require us to post collateral. We also enter into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon our credit ratings from S&P and Moody's. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if we were to be downgraded or lose our investment grade credit ratings (based on our senior unsecured debt rating), we would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In such cases, we believe an amount of several months of future payments (e.g., capacity payments) rather than a calculation of fair value is a reasonable estimate for the contingent collateral obligation, which has been factored into the disclosure below.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:


Credit-Risk-Related Contingent Features	March 31, 2026		December 31, 2025
Gross fair value of derivative contracts containing this feature	$	(2,321)	$	(1,307)
Offsetting fair value of derivative contracts under master netting arrangements	1,192		554
Net fair value of derivative contracts containing this feature	$	(1,129)	$	(753)

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 12 — Derivative Financial Instruments

As of March 31, 2026 and December 31, 2025, we posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.


	March 31, 2026		December 31, 2025
Cash collateral posted	$	1,904	$	1,399
Letters of credit posted	1,303		718
Cash collateral held	221		47
Letters of credit held	157		115
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1)(a)(b)(c)	2,972		2,670

__________

(a)Certain of our contracts contain provisions that allow a counterparty to request additional collateral when there has been a subjective determination that our credit quality has deteriorated, generally termed “adequate assurance”. Due to the subjective nature of these provisions, we estimate the amount of collateral that we may ultimately be required to post in relation to the maximum exposure with the counterparty.

(b)The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment and excludes any contracts with individual retail counterparties.

(c)A loss of investment grade credit rating would require a three-notch downgrade from current levels of BBB+ and Baa1 at S&P and Moody's, respectively.

We routinely enter into supply forward contracts with certain utilities with one-sided collateral postings only from us. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, we are required to post collateral once certain unsecured credit limits are exceeded.

13. Debt and Credit Agreements

Long-Term Debt

Calpine Acquisition

Upon completion of the acquisition of Calpine in January 2026, we assumed approximately $12.6 billion of debt inclusive of approximately $7.6 billion of corporate long-term debt, including senior unsecured and secured notes and corporate term loans in addition to approximately $5.0 billion of various project financing arrangements. Pursuant to the Exchange Offers discussed below, we issued new notes in January 2026 effectively replacing $2.3 billion of Calpine's senior unsecured and secured notes with Constellation senior unsecured notes. Using the proceeds from our January 2026 bond issuance, as discussed below, along with cash on hand and short-term debt, we repaid $2.5 billion of Calpine corporate term loans immediately after the acquisition closing, $1.25 billion of Calpine senior secured first lien notes in February 2026, and $1.4 billion of Calpine senior unsecured notes in March 2026.

As discussed above, the following project financing arrangements were assumed as part of the acquisition:

Geysers Power Company, LLC. We acquired the GPC first lien senior secured term loan facility, which includes a term loan and $250 million letter of credit facility, up to $50 million of which may be used for loans to finance energy storage projects ("sub-facility"). At acquisition, outstanding borrowings under the term loan and sub-facility were approximately $1.35 billion and $45 million, respectively. The GPC facility is secured by substantially all of the real and personal property of GPC and subsidiaries, primarily consisting of the Geysers Assets. The facility matures May 2029 and bears interest at SOFR plus 1.625%. As of March 31, 2026, there were $1.3 billion and $44 million of borrowings outstanding under the term loan and sub-facility, respectively.

Calpine Construction Finance Company, L.P. We acquired the CCFC first lien senior secured term loan facility with $2.1 billion outstanding borrowings at acquisition. The CCFC term loan facility is secured by certain real and personal property of CCFC, primarily seven natural gas-fired power plants. One plant secured under the facility, the Jack A. Fusco Energy Center (Fusco), is subject to sale in accordance with the DOJ resolution. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Under the terms of the loan facility, CCFC may require the consent of certain lenders to release Fusco as guarantor depending on the application of

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 13 — Debt and Credit Agreements

net sales proceeds. The term loan matures July 2030 and bears interest at SOFR plus 1.75%. As of March 31, 2026, there was $2.1 billion of borrowings outstanding under the term loan.

CDHI Intermediate Holdco, LLC. We acquired the CDHI facility (CDHI Revolver), a $1.20 billion letter of credit facility, up to $400 million of which can be used for revolving loans to finance construction of renewable energy projects. At acquisition, outstanding borrowings under the CDHI Revolver were $319 million. The CDHI Revolver is secured by substantially all of the assets of CDHI's subsidiaries in accordance with the terms of the agreement. The York Energy Centers that partially secure the CDHI Revolver are subject to sale in accordance with the DOJ resolution. Under the terms of the CDHI revolver, consent of certain lenders is required to release these plants as collateral. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Redemptions prior to March 2026 were based on SOFR plus 2.25%, and effective March 2026, redemptions bear interest at SOFR plus 2.375%. The CDHI Revolver matures March 2028. In March 2026 and April 2026, the CDHI revolver's total capacity was reduced by $250 million and $568 million, respectively. As of March 31, 2026, there was $309 million of borrowings outstanding under the credit facility.

Nova Power, LLC. We acquired the Nova Power, LLC credit agreement, which is comprised of a term loan, with $591 million of outstanding borrowings at acquisition, and a $80 million letter of credit facility. The agreement finances a portion of the cost of the development, construction, maintenance, and operation of the Nova Power battery storage project, and is secured by Nova Power's real and personal property. The credit agreement matures September 2031 and bears interest at SOFR plus 1.75%. As of March 31, 2026, there was $581 million of borrowings outstanding under the credit agreement.

Greenfield L.P. We acquired the Greenfield L.P. credit facility, which includes a term loan, with $342 million of outstanding borrowings at acquisition, and several letters of credit facilities, with issuing capacity of approximately $75 million. The Greenfield L.P. credit facility is secured by certain real and personal property, primarily the Greenfield Energy Center in Ontario, Canada. The credit facility matures November 2030 and bears interest at CORRA plus 1.875%. As of March 31, 2026, there was $330 million of borrowings outstanding under the facility.

Pin Oak Creek Energy Center LLC. We acquired Pin Oak Creek Energy Center's credit agreement pursuant with Texas Energy Fund (TEF), as lender, as administered by the Public Utility of Texas (PUCT). The loan proceeds are being used to finance eligible costs for the development (as defined in the agreement), construction, and installation of Pin Oak Creek Energy Center in Fairfield, Texas. The loan had outstanding borrowings of $230 million at acquisition. The loan matures October 2045 and bears interest at 3%. As of March 31, 2026, there was $246 million of borrowings outstanding under the loan.

Calpine Credit Agreements

As a result of the acquisition, we acquired Calpine's corporate secured and unsecured letters of credit facilities with capacity totaling $525 million and $200 million, respectively, at the time of acquisition.

The total capacity of assumed project and corporate credit facilities discussed above was approximately $2.3 billion at the time of acquisition, which is reduced by outstanding borrowings under the GPC facility and CDHI Revolver. At the time of acquisition, there were outstanding letters of credit on the assumed facilities of approximately $1.7 billion. See the Credit Facilities table below for additional information on credit facilities associated with these project financing arrangements.

Debt Exchange Offering

In December 2025, we announced that, in connection with the planned acquisition of Calpine by CEG Parent, we commenced private exchange offers and related consent solicitations with respect to certain outstanding debt of Calpine ("Exchange Offers"). Under the Exchange Offers, we solicited consents to holders of certain Calpine debt to amend the notes and the related indentures under which they were issued to eliminate substantially all of the restrictive covenants, restrictive provisions and events of default, other than payment-related and bankruptcy-related events of default. In January 2026, we completed the exchange offering, effectively replacing $2.3 billion of Calpine senior secured and unsecured notes with Constellation senior unsecured notes.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 13 — Debt and Credit Agreements

The terms of the debt issuance under the exchange are as follows:


Note	Interest Rate	Maturity	Issued Amount
2029 Senior Unsecured Notes	4.625%	February 2029	$	647
2031 Senior Unsecured Notes	5.000%	February 2031	848
2031 Senior Secured Notes	3.750%	March 2031	795
Total			$	2,290

Senior Note Issuance

In January 2026, we issued senior unsecured notes totaling $2.75 billion, the proceeds from which were used to pay down Calpine debt assumed. The terms of the debt issuance are reflected in the Debt Issuances and Redemptions table below.

Long-term Debt Summary

The following table presents the outstanding long-term debt, as of March 31, 2026 and December 31, 2025:


	Rates	Maturity Date	March 31, 2026		December 31, 2025
Long-term debt
Senior unsecured notes(a)(b)	3.75% - 6.50%	2028 - 2066	$	10,833	$	5,688
Tax-exempt notes(c)	4.10% - 4.45%	2029 - 2053	412		412
Notes payable and other	1.71% - 8.18%	2026 - 2035	85		53
Project finance:(b)
Variable rates	4.13% - 5.98%	2027 - 2030	5,274		597
Fixed rates	2.29% - 8.64%	2031 - 2048	876		653
Total long-term debt			17,480		7,403
Unamortized debt discount and premium, net			(16)		(1)
Unamortized fair value of debt			(19)		—
Unamortized debt issuance costs			(81)		(60)
Long-term debt due within one year			(370)		(92)
Long-term debt			$	16,994	$	7,250

________

(a)Includes January 2026 debt issuance of $2.75 billion and exchanged debt of $2.3 billion.

(b)Includes debt assumed in acquisition of Calpine.

(c)The Tax-exempt notes have a maturity date of June 2029 to April 2053, and a mandatory purchase date that ranges from April 2028 to June 2029.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 13 — Debt and Credit Agreements

Debt Issuances and Redemptions

During the three months ended March 31, 2026, the following long-term debt was issued (redeemed):


Type(a)	Interest Rate	Maturity	Amount
2028 Senior Notes(b)	3.90%	January 2028	$	900
2066 Senior Notes(b)	5.875%	January 2066	800
2031 Senior Notes(b)	4.40%	January 2031	750
2028 Floating Rate Senior Notes(b)	SOFR + 0.60%	January 2028	300
Pin Oak Creek Energy Center	3.00%	October 2045	16
Energy Efficiency Project Financing(c)	5.51%	December 2030	4
RPG Nonrecourse Debt	4.11%	March 2035	(2)
2031 Unsecured Notes	5.00%	August 2031	(2)
2029 Unsecured Notes	4.625%	August 2029	(3)
Antelope Valley DOE Nonrecourse Debt	2.29% - 3.56%	January 2037	(6)
Greenfield	CORRA + 1.875%	November 2030	(7)
Nova Power	SOFR + 1.75%	March 2028	(10)
Calpine Development Holdings	SOFR + 2.25%	March 2028	(11)
Continental Wind Nonrecourse Debt	6.00%	February 2033	(18)
Geysers Power Company	SOFR + 1.625%	May 2029	(35)
Calpine Term Loan	SOFR + 1.75%	February 2032	(860)
Calpine 2028 Senior Secured Notes	4.50%	February 2028	(1,250)
Calpine 2028 Senior Unsecured Notes	5.125%	March 2028	(1,400)
Calpine Term Loan	SOFR + 1.75%	January 2031	(1,650)
Total long-term debt issued (redeemed)			$	(2,484)

__________

(a)Does not include debt exchange activity discussed above.

(b)Relates to January 2026 debt issuance used to pay down Calpine corporate debt assumed.

(c)Represents funding to install energy conservation measures. The maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

DOE Loan Guarantee

In November 2025, the DOE Office of Energy Dominance Financing issued a guarantee for up to $1.0 billion for an unsecured loan from the Federal Financing Bank to support the restart of the Crane Clean Energy Center. The loan matures November 2055. Interest rates on the loan is fixed upon each advance at a spread of 0.375% above U.S. Treasuries of comparable maturity. There have been no borrowings on this loan as of the date of this filing.

Short-Term Borrowings

We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facility for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

Credit Agreements

In September 2025, we amended our existing revolving credit facility (RCF) to increase the available aggregate commitment from $4.5 billion to $7.0 billion, which included incremental revolving credit commitments of $2.5 billion and extension of the maturity date to September 2030. The incremental commitments became available upon the closing of the Calpine acquisition in January 2026. The RCF may be drawn down in the form of loans and/or to support commercial paper and letter of credit issuances.

The RCF fixed facility fee rate is 0.175% and borrowings under the RCF bear interest at a rate based upon either the Daily Simple SOFR rate or a Term SOFR rate, plus an adder based upon our credit rating. The adders for the

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 13 — Debt and Credit Agreements

Daily Simple SOFR-based borrowings and Term SOFR borrowings are 0.075% and 1.075%, respectively. The letters of credit bear interest at a rate of 1.075%.

If we were to lose our investment grade credit rating, the maximum adders for Daily Simple SOFR rate borrowings and Term SOFR rate borrowings would be 1.00% and 2.00%, respectively. The credit agreements also require us to pay facility fees based upon the aggregate commitments. The fees vary depending upon our credit rating.

Accounts Receivable Facility

The Accounts Receivable Facility (the Facility) provides NER access to revolving loans from a number of financial institutions (Lenders) secured by certain customer accounts receivable. The maximum funding limit of the Facility is $1.5 billion and matures December 2027. Draws and repayments related to the Facility will be reflected as Proceeds from short-term borrowings and Repayments of short-term borrowings, respectively, in the Consolidated Statements of Cash Flows. Draws on the Facility bear interest at a commercial paper rate or a Daily One Month Term SOFR or Term SOFR rate, plus an adder of 0.10% per annum. Interest is payable monthly. In January 2026, we drew on and repaid the full amount of the Facility. Subsequently, in February and March 2026, we drew on the Facility in the amounts of $600 million and $900 million, respectively. The Facility was fully drawn on and outstanding as of March 31, 2026. In April 2026, we issued a $1.5 billion term loan, as discussed below, and used the proceeds to repay $400 million of the Facility.

The Facility requires the balance of eligible receivables to be maintained at or above the balance of cash proceeds received from the Lenders. To the extent the eligible receivables decrease below such balance, we are required to repay cash to the Lenders. When eligible receivables exceed cash proceeds, we have the ability to increase the cash proceeds received up to the maximum funding limit. As of March 31, 2026, the balance of our eligible receivables exceeded the cash proceeds outstanding from the Lenders.

Credit Facilities Summary

As of March 31, 2026 and December 31, 2025, we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities:


Facility Type	Aggregate Bank Commitment		Facility Draws		Outstanding Letters of Credit(a)		Outstanding Commercial Paper(b)		Total Available Capacity
March 31, 2026
Revolving Credit Facility	$	7,000	$	—	$	701	$	1,957	$	4,342
Bilateral and letter of credit facilities(c)(d)	4,100		—		2,632		—		1,468
Accounts Receivable Facility	1,500		1,500		—		—		—
CDHI Revolver(d)	908		309		—		—		599
Liquidity Facility	971		—		758		—		199		(e)
Project Finance(d)	571		44		453		—		74
Total	$	15,050	$	1,853	$	4,544	$	1,957	$	6,682

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 13 — Debt and Credit Agreements


Facility Type	Aggregate Bank Commitment		Facility Draws		Outstanding Letters of Credit(a)		Outstanding Commercial Paper(b)		Total Available Capacity
December 31, 2025
Revolving Credit Facility	$	4,500	$	—	$	40	$	—	$	4,460
Bilaterals	2,350		—		1,276		—		1,074
Accounts Receivable Facility	1,500		—		—		—		1,500
Liquidity Facility	971		—		647		—		312		(e)
Project Finance	137		—		122		—		15
Total	$	9,458	$	—	$	2,085	$	—	$	7,361

__________

(a)Excludes an additional outstanding letter of credit which was not issued under these facilities of $15 million as of March 31, 2026 and December 31, 2025. See Note 15 — Commitments and Contingencies for additional information.

(b)Our commercial paper program is supported by the revolving credit agreement. In order to maintain our commercial paper program in the amounts indicated above, we must have a credit facility in place, at least equal to the amount of our commercial paper program. As of March 31, 2026 and December 31, 2025, the maximum program size of our commercial paper program was $7.0 billion and $4.5 billion, respectively. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility. The weighted average interest rate on commercial paper borrowings was 3.98% as of March 31, 2026. There were no commercial paper borrowings outstanding as of December 31, 2025.

(c)In February 2026, we increased the capacity to issue letters of credit by an additional $100 million each for two existing uncommitted bilateral facilities, and an additional $200 million for a third uncommitted bilateral facility. In February 2026, we initiated a new bilateral credit agreement for $400 million, with no maturity date. In February 2026, we entered into a $75 million uncommitted bilateral credit agreement. In March 2026, we increased the capacity to issue letters of credit for one committed bilateral facility by an additional $300 million and converted it to an uncommitted facility. In March 2026, a bilateral credit agreement initiated in March 2025 was extended for an additional two years to mature March 2028.

(d)Includes corporate and project-related facilities assumed in connection with Calpine acquisition in January 2026.

(e)The maximum amount of the bank commitment is not to exceed $971 million. The aggregate available capacity of the facility is subject to market fluctuations based on the value of U.S. Treasury Securities which determines the amount of collateral held in the trust. We may post additional collateral to borrow up to the maximum bank commitment. As of March 31, 2026 and December 31, 2025, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $957 million and $959 million, respectively.

Short-Term Loan Agreements

As of March 31, 2026 and December 31, 2025, we had the following short-term loan agreements, both of which are unsecured and reflected in Short-term borrowings in the Consolidated Balance Sheets:

Month Initiated

Interest Rate

Maturity

March 31, 2026

December 31, 2025

May 2025(a)

1-month SOFR + 0.90%

May 2026

900

September 2025

1-month SOFR + 0.90%

September 2026

750

__________

(a)In April 2026, we initiated a term loan for $1.5 billion, the proceeds of which were used to repay the May 2025 term loan.

Debt Covenants

As of March 31, 2026, we are in compliance with all debt covenants.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

14. Fair Value of Financial Assets and Liabilities

We measure and classify fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to liquidate as of the reporting date.

•Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

•Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

Fair Value of Financial Liabilities Recorded at Amortized Cost

The following table presents the carrying amounts and fair values of our long-term debt and SNF obligation as of March 31, 2026 and December 31, 2025. We have no financial liabilities classified as Level 1. The carrying amounts of the short-term liabilities as presented in the Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.


	March 31, 2026								December 31, 2025
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
			Level 2		Level 3		Total				Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year	$	17,364	$	13,994	$	3,475	$	17,469	$	7,342	$	6,995	$	666	$	7,661
SNF Obligation(a)	1,440		1,308		—		1,308		1,426		1,406		—		1,406

__________

(a)SNF Obligation is included in Other deferred credits and other liabilities in the Consolidated Balance Sheets.

Valuation Techniques Used to Determine Fair Value and Net Asset Value

Our valuation techniques used to measure the fair value and net asset value of the assets and liabilities are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of our 2025 Form 10-K except for certain assumed variable rate project financings which are valued using a model that estimates pricing using an internal rate of return calculation and benchmark indices, which may be adjusted for company or security specific risks, resulting in these being classified as Level 3.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

Recurring Fair Value Measurements

The following table presents assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2026 and December 31, 2025:


	March 31, 2026								December 31, 2025
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	332	$	—	$	—	$	332	$	42	$	—	$	—	$	42
NDT fund investments
Cash equivalents(b)	290		163		—		453		72		165		—		237
Equities	6,000		1,072		—		7,072		6,245		1,426		—		7,671
Fixed income	2,536		1,478		401		4,415		2,201		1,566		395		4,162
Private credit	—		—		133		133		—		—		132		132
Assets measured at NAV	—		—		—		7,421		—		—		—		7,194

NDT fund investments subtotal(c)	8,826		2,713		534		19,494		8,518		3,157		527		19,396
Rabbi trust investments	65		43		1		109		66		45		1		112
Investments in equities	60		—		—		60		87		—		—		87
Derivative assets
Economic hedges	2,102		11,063		8,994		22,159		1,114		7,449		3,830		12,393

Effect of netting and allocation of collateral	(1,940)		(10,361)		(5,950)		(18,251)		(889)		(6,853)		(3,256)		(10,998)
Derivative assets subtotal	162		702		3,044		3,908		225		596		574		1,395

Total assets measured at fair value	9,445		3,458		3,579		23,903		8,938		3,798		1,102		21,032



Liabilities
Derivative liabilities
Economic hedges	(2,349)		(11,613)		(7,300)		(21,262)		(1,148)		(8,021)		(4,062)		(13,231)
Effect of netting and allocation of collateral	2,222		11,283		6,429		19,934		1,065		7,657		3,628		12,350
Derivative liabilities subtotal	(127)		(330)		(871)		(1,328)		(83)		(364)		(434)		(881)
Deferred compensation obligation	—		(110)		—		(110)		—		(124)		—		(124)
Total liabilities measured at fair value	(127)		(440)		(871)		(1,438)		(83)		(488)		(434)		(1,005)
Total net assets	$	9,318	$	3,018	$	2,708	$	22,465	$	8,855	$	3,310	$	668	$	20,027

__________

(a)CEG Parent has $352 million and $70 million of Level 1 cash equivalents as of March 31, 2026 and December 31, 2025, respectively. We exclude cash of $734 million and $3,621 million, and restricted cash of $70 million and $57 million as of March 31, 2026 and December 31, 2025, respectively. CEG Parent has excluded an additional $15 million of cash as of March 31, 2026 and no additional cash exclusions as of December 31, 2025.

(b)Includes net liabilities of $231 million and $166 million as of March 31, 2026 and December 31, 2025, respectively, which consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.

(c)Includes total NDT derivative assets and liabilities that are not material, which have notional amounts of $1,053 million and $810 million as of March 31, 2026 and December 31, 2025, respectively. The notional principal amounts provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of our exposure to credit or market loss.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

As of March 31, 2026, our NDTs have outstanding commitments to invest in private credit, private equity, and real assets of $493 million, $445 million, and $656 million, respectively. These commitments will be funded by our existing NDT funds.

Equity Security Investments without Readily Determinable Fair Values. We hold investments without readily determinable fair values with carrying amounts of $113 million and $109 million as of March 31, 2026 and December 31, 2025, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three months ended March 31, 2026 and the year ended December 31, 2025.

Reconciliation of Level 3 Assets and Liabilities

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2026 and 2025:


	Three Months Ended March 31, 2026
	NDT Fund Investments		Derivatives			Rabbi Trust Investments		Total
Balance as of January 1, 2026	$	527	$	140		$	1	$	668
Contracts acquired at acquisition date	—		1,290		(a)	—		1,290
Total realized / unrealized gains (losses)
Included in net income (loss)	2		848		(b)	—		850
Included in Payables related to Regulatory Agreement Units	5		—			—		5
Change in collateral	—		(102)			—		(102)

Purchases	—		20			—		20
Sales	—		(5)			—		(5)


Transfers into Level 3	—		14		(c)	—		14
Transfers out of Level 3	—		159		(c)	—		159
Amortization of acquired contracts	—		(191)			—		(191)
Balance as of March 31, 2026	$	534	$	2,173		$	1	$	2,708
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2026	$	2	$	568		$	—	$	570

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities


	Three Months Ended March 31, 2025
	NDT Fund Investments		Derivatives			Rabbi Trust Investments		Total
Balance as of January 1, 2025	$	502	$	(1)		$	1	$	502
Total realized / unrealized gains (losses)
Included in net income (loss)	1		(131)		(b)	—		(130)

Change in collateral	—		67			—		67

Purchases	—		15			—		15
Sales	—		(3)			—		(3)
Settlements	(2)		—			—		(2)
Transfers into Level 3	1		(1)		(c)	—		—
Transfers out of Level 3	—		36		(c)	—		36
Balance as of March 31, 2025	$	502	$	(18)		$	1	$	485
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2025	$	1	$	(96)		$	—	$	(95)

__________

(a)Represents contracts acquired as part of the Calpine acquisition in January 2026. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

(b)Includes an addition of $89 million for realized losses and reduction of ($35) million for realized gains due to the settlement of derivative contracts for the three months ended March 31, 2026 and 2025, respectively.

(c)Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.

The following table presents the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2026 and 2025:


	Three Months Ended March 31,
	Operating Revenues				Purchased Power and Fuel				Other, net
	2026		2025		2026		2025		2026		2025
Total gains (losses) included in net income	$	582	$	38	$	75	$	(169)	$	2	$	1
Total unrealized gains (losses)	528		(8)		40		(88)		2		1

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

Derivatives

The following table presents the significant inputs to the forward curve used to value these positions:


Type of trade	Fair Value as of March 31, 2026		Fair Value as of December 31, 2025		Valuation Technique	Unobservable Input	2026 Range & Arithmetic Average		2025 Range & Arithmetic Average
Level 3 Derivatives—Economic hedges(a)(b)	$	1,694	$	(232)	Discounted Cash Flow	Forward power price (Non-congestion)	$2.43 - $181	$49	$4.77 - $154	$54
						Forward power price (Congestion)	$1.61 - $180	$52	$3.14 - $154	$50
						Forward gas price	($2.93) - $21	$3.20	($0.46) - $15	$3.52
					Option Model	Volatility percentage	10% - 110%	57%	14% - 197%	59%

__________

(a)The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions.

(b)The fair values do not include cash collateral posted (received) on Level 3 positions of $479 million and $372 million as of March 31, 2026 and December 31, 2025, respectively.

The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of our commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

15. Commitments and Contingencies

Commitments

Commercial Commitments. Commercial commitments as of March 31, 2026, representing commitments potentially triggered by future events, were as follows:


	Expiration within
	2026		2027		2028		2029		2030		2031 and thereafter		Total
Letters of credit	$	3,402	$	1,036	$	120	$	—	$	1	$	—	$	4,559
Surety bonds(a)	581		261		78		—		—		545		1,465
Guarantee under the Calpine AR Facility(b)	550		—		—		—		—		—		550
Total commercial commitments	$	4,533	$	1,297	$	198	$	—	$	1	$	545	$	6,574

__________

(a)Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(b)We have guaranteed the performance of Calpine Energy Solutions, LLC to Calpine Receivables, LLC under the Calpine AR Facility. The commitment represents the gross amount of sold receivables that are currently outstanding, limited to $550 million per the guarantee agreement. Refer to Note 7 — Accounts Receivable for additional information.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 15 — Commitments and Contingencies

First Priority Liens for Commodity Procurement and Risk Management Activities

Following the acquisition of Calpine in January 2026, the Company has assumed additional first-priority liens on Calpine assets, which are currently subject to first priority liens under various debt agreements, as collateral under certain of our power and natural gas agreements and certain of the interest rate swaps in order to reduce the cash collateral and letters of credit that would otherwise be provided to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under various debt agreements. As of March 31, 2026, the exposure was $220 million under these first priority liens for power and natural gas agreements and no exposure for the interest rate swaps.

Environmental Remediation Matters

General. Our operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property currently or formerly owned by us and of property contaminated by hazardous substances generated by us. We own or lease several real estate parcels, including parcels on which our operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, we are currently involved in proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, we cannot reasonably estimate whether we will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by us, environmental agencies, or others. Additional costs could have a material, unfavorable impact on our consolidated financial statements.

As of March 31, 2026 and December 31, 2025, we had accrued undiscounted amounts for environmental liabilities of $9 million in Accounts payable and accrued expenses and $169 million in Other deferred credits and other liabilities in the Consolidated Balance Sheets. See Note 18 — Commitments and Contingencies of our 2025 Form 10-K for additional information on environmental remediation matters. As of March 31, 2026, and through the date of filing, there have been no material changes in amounts recognized for the matters discussed in our 2025 Form 10-K.

Litigation

We are involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. We maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

As of March 31, 2026 and December 31, 2025, we had accrued $28 million and $15 million, respectively, in Accounts payable and accrued expenses and $108 million and $113 million, respectively, in Other deferred credits and other liabilities in the Consolidated Balance Sheets for liabilities related to litigation matters, including asbestos personal injury claims. See Note 18 — Commitments and Contingencies of our 2025 Form 10-K for additional information on asbestos personal injury claims

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Calpine was acquired on January 7, 2026, and is party to the same ongoing litigation proceedings as Constellation. See Note 18 — Commitments and Contingencies of our 2025 Form 10-K for additional information on this matter, which is likewise representative of the ongoing proceedings as it pertains to Calpine.

In March 2026, the Supreme Court of Texas denied plaintiffs’ petitions for a writ of mandamus in all five bellwether appeals. Plaintiffs have stated that they intend to seek rehearing before the Court. If the rehearing petitions in the bellwether cases are denied, the parties would return to the Multi-District-Litigation court to dispose of all of the remaining Winter Storm Uri tort claims pending against the power generator defendants.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 16 — Shareholders' Equity

16. Shareholders' Equity

Share Repurchase Program (CEG Parent)

During 2026, our Board of Directors approved a $4.4 billion increase relative to the remaining authorized amount to repurchase our outstanding common stock. No other repurchase plans or programs have been authorized. As of the date of this filing, we have approximately $4.7 billion of remaining authority for repurchases, which includes the impact of the open market repurchases, as discussed below. See Note 19 — Shareholders' Equity of our 2025 Form 10-K for additional information on our share repurchase program.

During the three months ended March 31, 2026 and 2025, no open market repurchases occurred. During April and May 2026, prior to this filing, we repurchased from the open market approximately 1.2 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $338 million.

Capped Call Options. During the first quarter of 2025, we entered into two structured share repurchase agreements. Under these agreements, we made up-front cash payments of $150 million in the first quarter of 2025 in exchange for the right to receive a predetermined amount of shares of our common stock or cash at expiration. Neither option was exercised during the second and third quarter of 2025, therefore we did not receive any shares at expiration. As a result, we received our initial up-front cash payments of $150 million plus a nominal cash premium during the second and third quarters of 2025. The cash received restored the remaining authority available for repurchases.

Changes in Accumulated Other Comprehensive Income (Loss) (All Registrants)

The following tables present changes in AOCI, net of tax, by component:


Three Months Ended March 31, 2026	Gains (losses) on Cash Flow Hedges		Pension and OPEB Items(a)		Foreign Currency Items		Total
Beginning balance	$	1	$	(2,413)	$	(13)	$	(2,425)
OCI before reclassifications	—		(25)		(3)		(28)
Amounts reclassified from AOCI	1		27		—		28
Net current-period OCI	1		2		(3)		—
Ending balance	$	2	$	(2,411)	$	(16)	$	(2,425)

Three Months Ended March 31, 2025
Beginning balance	$	(6)	$	(2,262)	$	(34)	$	(2,302)
OCI before reclassifications	—		(34)		8		(26)
Amounts reclassified from AOCI	2		17		—		19
Net current-period OCI	2		(17)		8		(7)
Ending balance	$	(4)	$	(2,279)	$	(26)	$	(2,309)

__________

(a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 11 — Retirement Benefits for additional information. See our Consolidated Statements of Operations and Comprehensive Income for individual components of AOCI.

The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss):


	Three Months Ended March 31,
		2026		2025
Pension and OPEB plans:

Actuarial loss reclassified to periodic benefit cost		$	(9)	$	(6)
Pension and OPEB plans valuation adjustment		8		12

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 17 — Variable Interest Entities

17. Variable Interest Entities

At March 31, 2026 and December 31, 2025, we consolidated several VIEs or VIE groups for which we are the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which we do not have the power to direct the entities’ activities and, accordingly, we were not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.

Consolidated VIEs

The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of March 31, 2026 and December 31, 2025. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit.


	March 31, 2026		December 31, 2025
Cash and cash equivalents	$	69	$	52
Restricted cash and cash equivalents	32		48
Accounts receivable, net	2,561		2,477
Inventories, net	13		13
Other current assets	34		29
Total current assets	2,709		2,619
Property, plant, and equipment, net	1,912		1,942
Other noncurrent assets	117		123
Total assets(a)	$	4,738	$	4,684

Short-term borrowings	$	1,500	$	—
Long-term debt due within one year	67		66
Accounts payable and accrued expenses	26		34
Other current liabilities	2		3
Total current liabilities	1,595		103
Long-term debt	551		578
Asset retirement obligations	234		231
Other deferred credits and other liabilities	1		2
Total deferred credits and other liabilities	235		233
Total liabilities	$	2,381	$	914

__________

(a)Our balances include unrestricted assets for current UEC assets of $17 million and $17 million, disclosed within other current assets in the table above, and noncurrent UEC assets of $112 million and $116 million, disclosed within other noncurrent assets in the table above, as of March 31, 2026 and December 31, 2025, respectively.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 17 — Variable Interest Entities

As of March 31, 2026 and December 31, 2025, our consolidated VIEs included the following:

Consolidated VIE or VIE groups:

Reason entity is a VIE:

Reason we are the primary beneficiary:

CRP - A collection of wind and solar project entities. We have a 51% equity ownership in CRP. See additional discussion below.

Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner.

We conduct the operational activities.

Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP.

Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner.

We conduct the operational activities.

Antelope Valley - A solar generating facility, which is 100% owned by us. Antelope Valley sells all of its output to PG&E through a PPA.

The PPA contract absorbs variability through a performance guarantee.

We conduct all activities.

NER - A bankruptcy remote, special purpose entity which is 100% owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity and gas.

NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 7 —Accounts Receivable for additional information on the sale of receivables.

Equity capitalization is insufficient to support its operations.

We conduct all activities.

Unconsolidated VIEs

Our variable interests in unconsolidated VIEs generally include an equity method investment and energy purchase and sale contracts. For the equity investment, the carrying amount of the investment is reflected in the Consolidated Balance Sheets in Other deferred debits and other assets, see Note 18 — Supplemental Financial Information for additional information. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to our involvement with the VIEs are predominantly related to working capital accounts and generally represent the amounts owed by, or owed to, us for the deliveries associated with the current billing cycles under the commercial agreements.

As of March 31, 2026 and December 31, 2025, we had significant unconsolidated variable interests in several VIEs for which we were not the primary beneficiary. These interests include certain commercial and securitization agreements.

The following table presents summary information about our significant unconsolidated VIE entities:


	March 31, 2026						December 31, 2025
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	710	$	575	$	1,285	$	711	$	—	$	711
Total liabilities(a)	97		550		647		95		—		95

Other ownership interests in VIE(a)	613		25		638		616		—		616

__________

(a)These items represent amounts on the unconsolidated VIE balance sheets, not in the Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 17 — Variable Interest Entities

As of March 31, 2026 and December 31, 2025, the unconsolidated VIEs consist of:

Unconsolidated VIE or VIE groups:

Reason entity is a VIE:

Reason we are not the primary beneficiary:

Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities.

PPA contracts that absorb variability through fixed pricing.

We do not conduct the operational activities.

Calpine Receivables, LLC - A bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Energy Solutions, LLC under the Accounts Receivable Sales Program

Equity capitalization is insufficient to support its operations.

We do not have the power to direct activities nor affect its financial performance

18. Supplemental Financial Information

Supplemental Consolidated Statements of Operations and Comprehensive Income Information

The following tables provide additional information about items recorded in the Consolidated Statements of Operations and Comprehensive Income.


	Three Months Ended March 31,
Operating revenues		2026		2025

Variable lease income		$	97	$	52


	Three Months Ended March 31,
Taxes other than income taxes		2026		2025
Property		$	102	$	72
Payroll		58		44
Gross receipts(a)		64		38
Other		5		6
Total		$	229	$	160

__________

(a)Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Supplemental Financial Information


	Three Months Ended March 31,
Other, net		2026		2025
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units		$	271	$	243
Non-Regulatory Agreement Units		155		94
Net unrealized gains (losses) on NDT funds
Regulatory Agreement Units		(206)		(117)
Non-Regulatory Agreement Units		(109)		(23)
Regulatory offset to NDT fund-related activities(b)		(52)		(103)
Total Decommissioning-related activities		59		94



Net unrealized gains (losses) from equity investments(c)		(27)		(268)

Other		14		20
Total		$	46	$	(154)

__________

(a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.

(b)Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units.

(c)Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock.

Supplemental Cash Flow Information

The following tables provide additional information about items recorded within our Consolidated Statements of Cash Flows.


		Three Months Ended March 31,
Depreciation, amortization, and accretion	Income statement location	2026		2025
PP&E	Depreciation and amortization	$	436	$	243
Nuclear fuel	Purchased power and fuel	244		232
Amortization of acquired derivative contracts(a)	Operating revenues or purchased power and fuel	228		—
ARO accretion	Operating and maintenance	174		158
Amortization of UECs	Operating revenues or purchased power and fuel	128		2
Amortization of intangible assets, net(b)	Depreciation and amortization	7		5
Other amortization	Operating revenues, purchased power and fuel, or interest expense, net	(15)		—
Total		$	1,202	$	640

__________

(a)Related to the amortization of acquired derivative contracts from the acquisition of Calpine.

(b)Primarily related to the amortization of customer relationships and trade names.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Supplemental Financial Information


	CEG Parent				Constellation
	Three Months Ended March 31,				Three Months Ended March 31,
Other non-cash operating activities	2026		2025		2026		2025
Other decommissioning-related activity(a)	$	(349)	$	(74)	$	(349)	$	(74)
Pension and non-pension postretirement benefit costs	50		38		50		38






Other	100		83		70		60
Total	$	(199)	$	47	$	(229)	$	24

__________

(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units.

The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported within our Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows.


March 31, 2026	CEG Parent		Constellation
Cash and cash equivalents	$	800	$	785
Restricted cash and cash equivalents	371		351

Total cash, restricted cash, and cash equivalents	$	1,171	$	1,136

December 31, 2025
Cash and cash equivalents	$	3,641	$	3,641
Restricted cash and cash equivalents	107		79

Total cash, restricted cash, and cash equivalents	$	3,748	$	3,720

March 31, 2025
Cash and cash equivalents	$	1,846	$	1,836
Restricted cash and cash equivalents	96		86

Total cash, restricted cash, and cash equivalents	$	1,942	$	1,922

For additional information on restricted cash, see Note 1 — Basis of Presentation of our 2025 Form 10-K. Calpine's restricted cash balances, included in our balances as of March 31, 2026, align with our current policy or represent other agreements that require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Supplemental Financial Information

Supplemental Balance Sheet Information

The following tables provides additional information about material items recorded in the Consolidated Balance Sheets.


Inventories, net	March 31, 2026		December 31, 2025
Materials and supplies	$	2,200	$	1,485
Natural gas, oil, and emission allowances	382		251
Total	$	2,582	$	1,736


	CEG Parent				Constellation
Accounts payable and accrued expenses	March 31, 2026		December 31, 2025		March 31, 2026		December 31, 2025
Accounts payable	$	2,708	$	2,813	$	2,697	$	2,801
Compensation-related accruals(a)	557		920		445		672
Taxes accrued(b)	484		246		483		245
Other accrued expenses	700		315		699		315
Total	$	4,449	$	4,294	$	4,324	$	4,033

__________

(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

(b)Includes $375 million as of December 31, 2025, related to nuclear PTC that was used to offset the current tax liability. No credits were utilized in the first quarter of 2026. See Note 6 — Government Assistance for additional information on the nuclear PTC.

The following table provides additional information about investments included in Other deferred debits and other assets in the Consolidated Balance Sheets.


Investments	March 31, 2026		December 31, 2025
Equity method investments	$	26	$	3
Other investments:
Employee benefit trusts and investments(a)	110		112
Equity investments with readily determinable fair values(b)	64		82
Equity investments without readily determinable fair values	113		109
Other available for sale debt security investments	1		1
Total	$	314	$	307

__________

(a)Debt and equity security investments are recorded at fair market value.

(b)Does not include the equity investments with readily determinable fair values that are recorded in Other current assets in the Consolidated Balance Sheets. See Note 14 — Fair Value of Financial Assets and Liabilities for additional information on investments in equities.


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

(Dollars in millions except per share data, unless otherwise noted)

Executive Overview

Constellation Energy Corporation, a Fortune 200 company headquartered in Baltimore, is the largest private-sector power producer in the world and the nation’s largest producer of clean and reliable energy. With 55 gigawatts of capacity from nuclear, natural gas, oil, geothermal, hydro, wind and solar facilities, our fleet has the generating capacity to power the equivalent of 27 million homes, providing about 10% of the nation’s clean energy and delivering the around-the-clock reliability needed to power America’s growing economy. We are also the largest nuclear energy company in the U.S. and a leading competitive retail supplier, serving approximately 2.5 million customer accounts nationwide, including 80% of the Fortune 100. We are committed to investing in innovation and new technologies to drive the transition to a reliable, sustainable and secure energy future.

Table of Contents

Significant Transactions and Developments

Acquisition of Calpine Corporation

On January 7, 2026, we acquired 100% of the outstanding equity of Calpine for a purchase price of approximately $21.8 billion. The merger consideration consisted of 50 million newly issued shares of our common stock, no par value, and approximately $4.5 billion in cash on hand. After considering divestitures connected with certain regulatory approvals, Calpine owns and operates a generation fleet of predominantly natural gas, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, in addition to a competitive retail electric supplier platform serving approximately 62 TWhs of load annually.

This acquisition is complementary to, and aligns strategically with, our existing business operations and provides both increased scale and meaningful market diversification. The merger couples the largest producer of clean, emissions-free energy with the reliable, dispatchable natural gas assets of Calpine, and also creates the nation’s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that enable us to meet growing demand with a broader array of energy and sustainability products. The addition of Calpine strengthens our essential role in providing clean, reliable energy as the nation seeks to transition to a more sustainable future, and will better position us to pursue investments in new and existing technologies to meet growing demand.

In March 2026, we entered into an agreement with LS Power Equity Advisors, LLC to sell five natural gas-fired generating facilities with approximately 4.4 GWs of capacity from Calpine's portfolio of generation assets located in PJM to satisfy regulatory commitments related to our acquisition of Calpine. The transaction is valued at $5.0 billion before closing adjustments and remains subject to customary closing conditions, including receipt of applicable regulatory approvals. Completion of this transaction, together with the planned divestiture of an additional ERCOT facility, is expected to satisfy the remaining regulatory commitments related to the merger.

See Note 2 — Mergers, Acquisitions, and Dispositions and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

New Data Center Facility at Freestone Energy Center

In the first quarter of 2026, we signed a new 380 MW agreement with Dallas-based CyrusOne, a leading global data center developer and operator, to connect and serve a new data center adjacent to the Freestone Energy Center, in Freestone County, Texas. The agreement provides CyrusOne with access to power, grid connectivity and site infrastructure needed to support development of the new facility, while ensuring electricity continues to flow to the regional grid and ensuring reliability for all customers and communities. Calpine has also entered into an exclusive agreement to provide power, grid connectivity and site infrastructure for Phase 2, which will be an additional 380 MWs. These agreements are in addition to the 400 MW agreements announced in the second half of last year between Calpine and CyrusOne for the Thad Hill Energy Center in Bosque County, Texas.

Pastoria Solar Project

In April 2026, we celebrated the commissioning of the 105 MW Pastoria Solar Project, the largest renewable energy project contracted by the California Department of Water Resources to date in its mission to fully decarbonize its operations by 2035. The Pastoria Solar Project connects to the grid through the interconnection facilities at our highly efficient 750 MW natural gas-fired combined-cycle generating facility. Also, co-located with the Pastoria Solar Project is the Pastoria Power Bank, a 80 MW/320 MWh Battery Energy Storage System, which will be coming online during the spring/summer of 2026. The Pastoria Power Bank is contracted and supported by a 15-year power purchase agreement with Pacific Gas and Electric Company.

Pin Oak Creek Energy Center

In April 2026, our Pin Oak Creek Energy Center achieved commercial operation. Pin Oak Creek is a 460-megawatt, state-of-the-art natural gas facility designed to provide reliable, dispatchable power to the ERCOT grid. As a peaking facility, it is built to operate when demand is highest and reliability matters most, while also maintaining the flexibility to run longer if system conditions require it. The project is a direct response to Texas’ continued growth and increasing electricity demand across homes, businesses, and industry. Pin Oak Creek will play a critical role in strengthening grid reliability and supporting the state’s economic momentum.

Table of Contents

Other Key Business Drivers

PJM Market Reform

In January 2026, the National Energy Dominance Council, with support from Governors within the PJM territory, urged PJM to file proposed tariff revisions at FERC to improve reliability and cost-effectiveness within its capacity auctions. During the first quarter of 2026, PJM began stakeholder discussions and preparatory work in response to this directive, including evaluation of a potential reliability backstop mechanism, enhancements to large load forecasting methodologies, and actions to accelerate generator interconnection studies. In February 2026, PJM filed tariff revisions proposing to extend the existing RPM capacity market price collar—consisting of a price cap of approximately $325/MW‑day and a price floor of approximately $175/MW‑day—for the 2028/2029 and 2029/2030 Base Residual Auctions. In an order issued by FERC in April 2026, FERC accepted PJM’s tariff revisions, allowing the continued application of the price collar for the specified delivery years. The Commission found the filing sufficiently justified to proceed, citing ongoing reliability concerns and extraordinary demand growth, including data center load expansion, and anticipated market reforms.

FERC Issues Order in PJM Show Cause Proceeding

In December 2025, FERC issued a draft order finding PJM's tariff unjust and unreasonable as it relates to colocated load, citing lack of sufficient clarity and consistency regarding rates, terms, and conditions of service for interconnection customers serving co-located load. The draft order also found that behind-the-meter generation rules in PJM's current tariff are no longer appropriate. PJM's current tariff requires that all co-located load be served through the PJM transmission system and that any planned modifications to generating facilities would require reliability studies and be subject to PJM's approval. FERC is now directing PJM to revise its tariff to: a) detail the terms and conditions for interconnection customers serving co-located load, b) require transmission customers serving co-located load to choose from four specific service options, and c) revise behind-the-meter generation rules, including the development of a transition period and grandfather clause for certain existing contracts. Through the date of this filing, PJM had not filed its final compliance tariff revisions, and the ultimate form and timing of these changes remain subject to further stakeholder processes and FERC review.

Russia and Ukraine Conflict

We are closely monitoring developments of the ongoing Russia and Ukraine conflict, including United States, United Kingdom, European Union, and Canadian sanctions, and legislation that may impact exports and imports of Russian nuclear fuel supply and enrichment activities, as well as the potential for Russia to limit fuel deliveries. The U.S. “Prohibiting Russian Uranium Imports Act” became effective in August 2024, banning the import of low-enriched uranium into the U.S. that is produced in Russia or by Russian entities, absent a waiver from the DOE. Under a corollary bill, the Department of Energy has begun the process of distributing billions of dollars to support expansion of the domestic nuclear fuel cycle within the United States to improve emissions-free energy security. In November 2024, the Russian government issued a decree imposing temporary restrictions on the export of enriched uranium from Russia to the U.S. but allowing for a special Russian export license to be issued for individual shipments. Our nuclear fuel is obtained predominantly through long-term uranium supply and service contracts. We work with a diverse set of domestic and international suppliers years in advance to procure our nuclear fuel to support our refueling needs and mitigate the risk of exposure to Russian nuclear fuel supply. Recognizing the potential for the continuing conflict to impact our longer-term security and cost of supply, we have entered into contracts to increase the size of our nuclear fuel inventory. Our fuel procurement activities comply with all U.S. and international trade laws and we continue to take advantage of all available avenues to maintain continuity in our nuclear fuel supply, including working with the U.S. Government and our diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term.

Table of Contents

Environmental Regulation

California Assembly Bill 32, as amended by Senate Bill 32 in 2016, directed the California Air Resources Board (CARB) to adopt regulations to achieve the maximum technologically feasible and cost-effective reductions in GHG emissions, targeting statewide GHG emissions at 1990 levels by 2020 and to at least 40% below 1990 levels by 2030. The California Climate Crisis Act was enacted in 2022 and further establishes the state's policy to achieve net zero GHG emissions as soon as possible, but no later than 2045, and to reduce statewide anthropogenic GHG emissions to 85% below 1990 levels by 2045. To achieve these targets, CARB has promulgated complementary regulatory measures, including the Cap-and-Trade Program and Mandatory Greenhouse Gas Emissions Reporting Regulation. Covered entities, such as our power plants, must surrender compliance instruments, which include both allowances and offset credits, in an amount equivalent to their GHG emissions. Assembly Bill 398, enacted in 2017, authorized the extension of the Cap-and-Trade Program through 2030 and required several changes to the program, including establishing a price ceiling and other price mitigative mechanisms and limiting the amount of offsets allowed to comply with the regulation. In September 2025, California Governor Gavin Newsom signed AB 1207 and SB 840 into law, extending the state’s Cap-and-Trade Program through January 1, 2046, and renaming it the “Cap and Invest" Program.

In September 2021, Illinois Governor JB Pritzker signed into law the Climate and Equitable Jobs Act, which, among other things, establishes a schedule for eliminating CO2 emissions by EGUs. Under that schedule, privately owned natural gas units that exceed an established level of NOx or SO2 emissions and are located within three miles of an environmental justice community, or an equity investment-eligible community must permanently eliminate CO2 and co-pollutant emissions by January 1, 2030, subject to certain reliability exceptions. Unless relief from the requirements is provided this could require our natural gas generation facility Zion Energy Center, acquired as part of Calpine, to shut down by January 2030.

See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on environmental legislation and regulation we are subject to.

Critical Accounting Policies and Estimates

Management makes a number of significant estimates, assumptions, and judgments in the preparation of our financial statements. At March 31, 2026, our critical accounting policies and estimates had not changed significantly from December 31, 2025. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates of our 2025 Form 10-K for further information.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth our consolidated GAAP Net Income (Loss) Attributable to Common Shareholders for the three months ended March 31, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three months ended March 31, 2026 and 2025, see the discussions of Results of Operations below.


	Three Months Ended March 31,					$ Change
		2026			2025
GAAP Net Income (Loss) Attributable to Common Shareholders			$	1,590		$	118	$	1,472

Adjusted (non-GAAP) Operating Earnings. We utilize Adjusted (non-GAAP) Operating Earnings (and/or its per share equivalent) in our internal analysis, and in communications with investors and analysts, as a consistent measure for comparing our financial performance and discussing the factors and trends affecting our business. The presentation of Adjusted (non-GAAP) Operating Earnings is intended to complement and should not be considered an alternative to, nor more useful than, the presentation of GAAP Net Income.

Table of Contents

The table below provides a reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings. Adjusted (non-GAAP) Operating Earnings is not a standardized financial measure and may not be comparable to other companies’ presentations of similarly titled measures.

Unless otherwise noted, the income tax impact of each reconciling adjustment between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part, which may result in an effective tax rate that differs from the marginal rate. The marginal statutory income tax rate was 25.5% for the three months ended March 31, 2026 and 2025. The following table provides a reconciliation between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings for the three months ended March 31, 2026 compared to the same period in 2025.



















	Three Months Ended March 31,
	2026				2025
(In millions, except per share data)			Earnings Per Share(a)				Earnings Per Share(a)
GAAP Net Income (Loss) Attributable to Common Shareholders	$	1,590	$	4.49	$	118	$	0.38
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $247 and $169, respectively)(b)	(721)		(2.03)		505		1.61
Decommissioning-Related Activities (net of taxes of $79 and $31, respectively)(c)	(174)		(0.49)		19		0.06
Amortization of Acquired Commodity Contracts (net of taxes of $53 and $—, respectively)(d)	154		0.44		—		—
Calpine Merger and Integration Costs (net of taxes of $22 and $4, respectively)(e)	119		0.34		13		0.04
Plant Retirements and Divestitures (net of taxes of $— and $4, respectively)	—		—		11		0.03
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $7 and $3, respectively)	20		0.06		9		0.03

Income Tax-Related Adjustments	(13)		(0.04)		—		—
Noncontrolling Interests(f)	(3)		(0.01)		(2)		(0.01)
Adjusted (non-GAAP) Operating Earnings	$	972	$	2.74	$	673	$	2.14

__________

(a)Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 354 million and 314 million for the three months ended March 31, 2026 and 2025, respectively.

(b)Includes unrealized gains and losses on economic hedges, interest rate swaps, and fair value adjustments related to gas imbalances and equity investments.

(c)Reflects all gains and losses associated with NDTs, ARO accretion, ARC depreciation, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units. The tax effects of Regulatory Agreement Units result in a 100% effective tax rate under contractual offset accounting. Additionally, the tax effects of NDT investment returns result in different effective tax rates depending on whether the underlying funds are held within qualified or non-qualified trusts.

(d)In 2026, reflects the non-cash impacts of the amortization of certain commodity contracts recorded at fair value associated with the Calpine acquisition.

(e)Reflects costs associated with the completion of the Calpine merger and subsequent integration of its operations. Certain of these transaction-related expenses are not tax deductible.

(f)Represents elimination of the noncontrolling interest portion of certain adjustments included above.

Table of Contents

Results of Operations


	Three Months Ended March 31,					$ Change
		2026			2025
Operating revenues			$	11,122		$	6,788	$	4,334
Operating expenses
Purchased power and fuel			6,352			4,384		1,968
Operating and maintenance			1,780			1,545		235
Depreciation and amortization			443			248		195
Taxes other than income taxes			229			160		69
Total operating expenses			8,804			6,337		2,467

Gain (loss) on sales of assets			14			—		14


Operating income (loss)			2,332			451		1,881
Other income and (deductions)
Interest expense, net			(253)			(146)		(107)
Other, net			46			(154)		200
Total other income and (deductions)			(207)			(300)		93
Income (loss) before income taxes			2,125			151		1,974
Income tax (benefit) expense			530			22		508
Equity in income (losses) of unconsolidated affiliates			8			—		8
Net income (loss)			1,603			129		1,474
Net income (loss) attributable to noncontrolling interests			13			11		2
Net income (loss) attributable to common shareholders			$	1,590		$	118	$	1,472

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. The variance in Net income (loss) attributable to common shareholders was favorable by $1,472 million primarily due to:

•Addition of Calpine operations acquired in January 2026, inclusive of the impacts of purchase accounting. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information;

•Favorable net unrealized gains on economic hedges;

•Favorable decommissioning-related activities primarily driven by the Q1 2026 nuclear ARO update. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information;

•Lower net unrealized loss on equity investments; and

•Favorable net market and portfolio conditions primarily driven by higher capacity revenues partially offset by higher costs related to a significant weather event in the first quarter of 2026 and lower CMC program revenue.

The favorable items were partially offset by:

•Unfavorable impacts from nuclear outages.

Table of Contents

Operating revenues. Our six reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, Other Power Regions, and Calpine. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.

With the exception of Calpine's natural gas sales, which are included in the Calpine segment, wholesale and retail sales of natural gas, as well as sales of other energy-related products and sustainable solutions and other miscellaneous business activities that are not significant to overall results of operations are reported under Other and not allocated to a segment.

For the three months ended March 31, 2026 compared to 2025, Operating revenues were as follows:


	Three Months Ended March 31,
		2026		2025		$ Change		% Change
Mid-Atlantic		$	1,847	$	1,665	$	182	10.9	%
Midwest		1,732		1,404		328		23.4	%
New York		569		562		7		1.2	%
ERCOT		370		398		(28)		(7.0)	%
Other Power Regions		1,487		1,556		(69)		(4.4)	%
Calpine		2,395		—		2,395		100.0	%
Total reportable segment revenues		8,400		5,585		2,815		50.4	%
Other		1,407		1,490		(83)		(5.6)	%
Unrealized gains (losses)(a)		1,315		(287)		1,602
Total Operating revenues		$	11,122	$	6,788	$	4,334	63.8	%

__________

(a)% Change in unrealized gains (losses) is not a meaningful measure.

Table of Contents

Sales and Supply Sources. Our sales and supply volumes (GWhs) by segment are summarized below:


	Three Months Ended March 31,
(GWhs)		2026	2025	Change	% Change
Nuclear Generation(a)
Mid-Atlantic		13,326	13,177	149	1.1	%
Midwest		22,974	23,596	(622)	(2.6)	%
New York		6,014	6,280	(266)	(4.2)	%
ERCOT		2,352	2,529	(177)	(7.0)	%
Total Nuclear Generation		44,666	45,582	(916)	(2.0)	%

Natural Gas, Oil, and Renewables(a)
Mid-Atlantic		740	632	108	17.1	%
Midwest		344	385	(41)	(10.6)	%

ERCOT		2,738	3,084	(346)	(11.2)	%
Other Power Regions		1,742	1,804	(62)	(3.4)	%
Calpine		26,497	—	26,497	100.0	%
Total Natural Gas, Oil, and Renewables		32,061	5,905	26,156	442.9	%

Purchased Power
Mid-Atlantic		4,094	4,794	(700)	(14.6)	%
Midwest		417	488	(71)	(14.5)	%

ERCOT		686	659	27	4.1	%
Other Power Regions		9,317	10,994	(1,677)	(15.3)	%
Calpine		2,089	—	2,089	100.0	%
Total Purchased Power		16,603	16,935	(332)	(2.0)	%

Total Supply/Sales by Segment
Mid-Atlantic		18,160	18,603	(443)	(2.4)	%
Midwest		23,735	24,469	(734)	(3.0)	%
New York		6,014	6,280	(266)	(4.2)	%
ERCOT		5,776	6,272	(496)	(7.9)	%
Other Power Regions		11,059	12,798	(1,739)	(13.6)	%
Calpine		28,586	—	28,586	100.0	%
Total Supply/Sales by Segment		93,330	68,422	24,908	36.4	%

__________

(a)Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants.

Table of Contents

Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for our plants that reflects our ownership percentage for stations operated by us and excludes Salem and STP, which are operated by PSEG and STPNOC, respectively. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a unit (or combination of units) over a period of time to its output if the unit had operated at net monthly mean capacity for that time period. We consider capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. We have included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.


	Three Months Ended March 31,
		2026		2025
Nuclear fleet capacity factor		92.3	%	94.1	%
Refueling outage days		99		88
Non-refueling outage days		—		—

Equivalent Forced Outage Factor (Natural Gas, Oil, and Pumped-storage Hydro). As a result of our expanded fleet following the acquisition of Calpine in January 2026, we now consider EFOF to be a key operational metric beginning in 2026. EFOF represents the percentage for which a generating unit is not available due to forced outages and forced deratings in a given period. We consider to be a useful measure in analyzing the reliability and performance of our natural gas, oil, and pumped-storage hydro fleet. The EFOF for the three months ended March 31, 2026 is 4.5%. This operational metric is being included as a complement to the financial information provided in accordance with GAAP. However, as an operational metric, it may not be calculated or presented in a manner comparable to similar metrics used by other companies.

Electricity Prices. As a producer and supplier of electricity, the price of electricity has a significant impact on our operating revenues and purchased power cost. We report the sale and purchase of electricity in the spot market on a net hourly basis in either Operating revenues or Purchased power and fuel expense based on our net hourly position. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the geographic region, weather, ongoing competition, emerging technologies, as well as macroeconomic and regulatory factors. The following table presents an average day-ahead around-the-clock reference price ($/MWh) for the periods presented for zones/hubs in each ISO/RTO where we have significant activity. This does not reflect prices we ultimately realized.


	Three Months Ended March 31,
ISO/RTO		2026		2025		$ Change		% Change
PJM - PJM West		$	97.16	$	53.69	$	43.47	81.0	%
PJM - ComEd		50.71		35.31		15.40		43.6	%
NYISO - Central		112.23		75.31		36.92		49.0	%
ERCOT - North		40.65		31.39		9.26		29.5	%
ERCOT - Houston		38.55		31.73		6.82		21.5	%
ISO-NE - Southeast Massachusetts		118.82		104.75		14.07		13.4	%
CAISO - NP15		29.01		40.96		(11.95)		(29.2)	%

Table of Contents

Capacity Prices. We participate in capacity auctions in each ISO/RTO where we have qualifying generating assets. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a material impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis in either Operating revenues or Purchased power and fuel expense. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The following table presents the average capacity prices ($/MW Day) for each ISO/RTO in which we have significant activity. Prices reflect the weighted average prices for the various auction periods within the three months ended March 31, 2026 and 2025.

We also enter into bilateral capacity contracts at negotiated contract prices. These contracts primarily relate to resource adequacy in CAISO and have a material impact on our operating revenues. Negotiated contract prices from these bilateral contracts are not included in the table below.


	Three Months Ended March 31,
ISO/RTO		2026		2025		$ Change		% Change
PJM - Eastern Mid-Atlantic Area Council		$	269.92	$	53.60	$	216.32	403.6	%
PJM - ComEd		269.92		28.92		241.00		833.3	%
NYISO - Rest of State		112.33		86.33		26.00		30.1	%
ISO-NE - Rest of Pool(a)		84.37		82.57		1.80		2.2	%

__________

(a)We did not have significant activity at this zone for the three months ended March 31, 2025.

ZEC Prices. We are compensated through state programs for the emissions-free attributes of our nuclear generation. The following table includes the average ZEC reference prices ($/MWh) for each state and associated segment in which state programs have been enacted. Gross prices reflect the weighted average price for the various delivery periods within the three months ended March 31, 2026 and 2025 and may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed below.


	Three Months Ended March 31,
State (Segment)(a)		2026		2025		$ Change		% Change
New Jersey (Mid-Atlantic)(b)		$	—	$	10.00	$	(10.00)	(100.0)	%
Illinois (Midwest)		1.17		9.38		(8.21)		(87.5)	%
New York (New York)		14.76		18.27		(3.51)		(19.2)	%

__________

(a)See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on the plants receiving payments through state programs.

(b)The New Jersey ZEC program concluded in May 2025.

Illinois CMC Price. The price received (paid) for each CMC is determined by the IPA monthly by subtracting energy and capacity index prices from the bid price, which resulted in $33.43 per MWh for the period June 2024 through May 2025 and $33.50 per MWh for the period June 2025 through May 2026. If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us. If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd. The average CMC prices per MWh were ($26.18) and ($2.04) for the three months ended March 31, 2026 and 2025, respectively. The average CMC prices may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed below.

Nuclear PTC. Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh and is subject to phase-out when annual gross receipts are between $26.00 per MWh and $44.75 per MWh for 2025. We expect the inflation factor for 2026 to be published in the second or third quarter of 2026. Both the amount of the PTC and the gross receipts thresholds adjust for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year.

Table of Contents

Many of the state-sponsored programs (e.g., ZECs and CMCs) providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC.

The following table summarizes the impacts to Operating revenues related to the benefits of nuclear PTC and state-sponsored programs subject to refund or pass through as described above for the three months ended March 31, 2026 compared to 2025:


	Three Months Ended March 31,
		2026		2025		$ Change		% Change
Nuclear PTC revenue(a)		$	10	$	—	$	10	100.0	%
State-sponsored programs net revenue(b)		(285)		110		(395)		(359.1)	%

__________

(a)Our estimate required the exercise of judgment in determining the amount of nuclear PTC expected for each of our nuclear units. Refer to Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.

(b)Includes only state-sponsored programs that have contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received.

For the three months ended March 31, 2026 compared to 2025, changes in Operating revenues by segment were approximately as follows:


	Three Months Ended March 31
		$ Change		% Change		Description
Mid-Atlantic		$	182	10.9	%	• favorable retail load revenue of $315 primarily due to higher contracted energy prices • favorable wholesale load revenue of $100 primarily due to higher contracted energy prices, partially offset by lower load volumes; partially offset by • unfavorable realized economic hedges of $215 due to settled prices relative to hedged prices
Midwest		328		23.4	%	• favorable net generation and wholesale load revenue of $370 primarily due to higher energy prices and higher load volumes, partially offset by lower generation volumes • favorable retail load revenue of $210 primarily due to higher contracted energy prices • favorable net capacity revenue of $90 primarily due to higher prices; partially offset by • unfavorable CMC program revenue of $350 primarily due to higher energy and capacity prices
New York		7		1.2	%	• favorable net generation revenue of $100 associated with the sale of generation volumes relative to purchased power to supply load primarily due to higher energy prices; partially offset by • unfavorable realized economic hedges of $95 due to settled prices relative to hedged prices
ERCOT		(28)		(7.0)	%	• no individually significant drivers
Other Power Regions		(69)		(4.4)	%	• unfavorable wholesale load revenue of $125 primarily due to lower load volumes in New England
Calpine		2,395		100.0	%	• represents the operating revenues associated with our Calpine segment since the date of acquisition

Table of Contents


	Three Months Ended March 31
		$ Change		% Change		Description
Other		(83)		(5.6)	%	• current year includes unfavorable amortization associated with certain commodity contracts related to the Calpine acquisition of $215; partially offset by • favorable retail gas revenue of $165 primarily due to higher gas prices
Unrealized gains or losses(a)(b)		1,602				• gains on economic hedging activities of $1,315 in 2026 compared to losses of $287 in 2025, inclusive of Calpine
Total		$	4,334	63.8	%

__________

(a)% Change in unrealized gains or losses is not a meaningful measure.

(b)See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.

Purchased power and fuel. See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including sales and supply sources by segment, nuclear fleet capacity factor, EFOF, capacity prices, and electricity prices.

With the exception of Calpine's natural gas activity, which is included in the Calpine segment, wholesale and retail natural gas activity, as well as other miscellaneous business activities that are not significant to overall results of operations are reported under Other and are not allocated to a segment.

For the three months ended March 31, 2026 compared to 2025, Purchased power and fuel expense were as follows:


	Three Months Ended March 31,
		2026		2025		$ Change		% Change
Mid-Atlantic		$	1,035	$	856	$	179	20.9	%
Midwest		878		554		324		58.5	%
New York		160		161		(1)		(0.6)	%
ERCOT		161		184		(23)		(12.5)	%
Other Power Regions		1,220		1,362		(142)		(10.4)	%
Calpine		1,269		—		1,269		100.0	%
Total segment purchased power and fuel		4,723		3,117		1,606		51.5	%
Other		1,375		1,233		142		11.5	%
Unrealized losses (gains)(a)		254		34		220
Total purchased power and fuel		$	6,352	$	4,384	$	1,968	44.9	%

__________

(a)% Change in unrealized losses (gains) is not a meaningful measure.

Table of Contents

Natural Gas Prices. As an owner-operator of a large fleet of natural gas generation facilities, the cost of our natural gas supply has a significant impact on our Purchased power and fuel expense. The following table summarizes the average daily reference price ($/MMBtu) for the periods presented in each geographic region where we have significant activity. This does not reflect prices we ultimately realized.


	Three Months Ended March 31,
Location		2026		2025		$ Change		% Change
Henry Hub		$	4.90	$	4.28	$	0.62	14.5	%
Transco Zone 6(a)		9.48		6.06		3.42		56.4	%
Houston Ship Channel(b)		3.26		3.46		(0.20)		(5.8)	%
PG&E Citygate(c)		2.07		3.71		(1.64)		(44.2)	%
Algonquin Citygate(d)		14.08		11.83		2.25		19.0	%

__________

(a)Transcontinental Gas pipeline located in Mid-Atlantic region.

(b)Houston-area pipeline and industrial network located in ERCOT region.

(c)Pacific Gas & Electric Company virtual trading point located in West region.

(d)Algonquin Gas Transmission physical delivery point located in New England region.

For the three months ended March 31, 2026 compared to 2025, changes in Purchased power and fuel expense by segment were approximately as follows:


	Three Months Ended March 31
		$ Change		% Change		Description
Mid-Atlantic		$	179	20.9	%	• unfavorable $350 associated with purchased power to supply load, net of generation, primarily due to higher energy prices, higher prices associated with net capacity costs, and higher costs related to a significant weather event in January 2026; partially offset by • favorable realized economic hedges of $190 due to settled prices relative to hedged prices
Midwest		324		58.5	%	• unfavorable $310 associated with purchased power to supply load, net of generation, primarily due to higher costs related to a significant weather event in January 2026
New York		(1)		(0.6)	%	• no individually significant drivers
ERCOT		(23)		(12.5)	%	• no individually significant drivers
Other Power Regions		(142)		(10.4)	%	• favorable $80 associated with purchased power to supply load primarily due to lower energy prices in the West
Calpine		1,269		100.0	%	• represents the purchased power and fuel associated with our Calpine segment since the date of acquisition
Other		142		11.5	%	• unfavorable net wholesale gas purchases, inclusive of realized economic hedges, of $175 primarily due to higher gas prices
Unrealized gains or losses(a)(b)		220				• losses on economic hedging activities of $254 in 2026 compared to losses of $34 in 2025, inclusive of Calpine
Total		$	1,968	44.9	%

__________

(a)% Change in unrealized gains or losses is not a meaningful measure.

(b)See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.

Table of Contents

The changes in Operating and maintenance expense consisted of the following:


	Three Months Ended March 31
	2026 vs. 2025
	Increase (Decrease)
Labor, contracting, and materials(a)	$	175
Calpine merger and integration costs	126
Nuclear refueling outage costs(b)	51
Decommissioning-related activities	(272)
Other	155
Total increase	$	235

__________

(a)Primarily reflects increased employee-related costs, including labor and other incentives, as well as higher contracting expense, driven in large part by the addition of Calpine's operations beginning in January 2026.

(b)Includes the co-owned Salem and STP generating units

Depreciation and amortization expense increased by $195 million for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to the additional depreciation and amortization associated with assets acquired from Calpine beginning in January 2026. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

Interest expense, net increased by $107 million for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to a net increase in outstanding debt as a result of the debt assumed and related financing transactions following the acquisition of Calpine in January 2026. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Other, net was favorable for the three months ended March 31, 2026 compared to the same period in 2025, due to activity described in the table below:


		Income (Deductions)
	Three Months Ended March 31,
		2026		2025
Decommissioning-related activities(a)		$	59	$	94
Net unrealized gains (losses) from equity investments(b)		(27)		(268)
Other		14		20
Other, net		$	46	$	(154)

__________

(a)Includes net realized and net unrealized gains (losses) on NDT fund investments, the elimination of decommissioning-related activities, and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units. See Note 9 — Asset Retirement Obligations and Note 18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information.

(b)Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock.

Effective income tax rates were 24.9% and 14.6% for the three months ended March 31, 2026 and 2025, respectively. The change in effective tax rate for 2026 is primarily due to the decrease in share-based payment awards as well as lower qualified NDT fund income which is taxed at a higher rate. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Table of Contents

Liquidity and Capital Resources

All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

Our operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. Our business is capital intensive and requires considerable capital resources. We annually evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade ratings while meeting our cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures, such as our acquisition of Calpine and planned restart of Crane. A broad spectrum of financing alternatives beyond the core financing options can be used to meet our needs and fund growth, including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., issuing equity, joint ventures, minority partners, etc.). Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions. If these conditions deteriorate to the extent that we no longer have access to the capital markets at reasonable terms, we have access to credit facilities with aggregate bank commitments of $15.1 billion. We utilize our credit facilities to support our commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. We expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Cash Flow Activities

The following table summarizes our cash flow activities for the three months ended March 31, 2026 and 2025, respectively:


	Three Months Ended March 31,
	2026		2025		$ Change
Cash, restricted cash, and cash equivalents at beginning of period	$	3,748	$	3,129	$	619
Net cash provided by (used in):
Operating activities	425		107		318
Investing activities	(3,732)		(886)		(2,846)
Financing activities	730		(408)		1,138
Net increase (decrease) in cash, restricted cash, and cash equivalents	(2,577)		(1,187)		(1,390)

Cash, restricted cash, and cash equivalents at end of period	$	1,171	$	1,942	$	(771)

Net Cash Provided By (Used In) Operating Activities

Cash provided by operating activities was $425 million and $107 million for the three months ended March 31, 2026 and 2025, respectively. Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted for changes in working capital in the normal course of business. Additionally, the increase in cash provided by operating activities was due to cash inflows associated with a decrease in collateral posted. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Net Cash Provided By (Used In) Investing Activities

Cash used in investing activities was ($3,732) million and ($886) million for the three months ended March 31, 2026 and 2025, respectively. The change is primarily related to cash paid, net of cash acquired, for the Calpine acquisition. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

Table of Contents

Net Cash Provided By (Used In) Financing Activities

Cash provided by financing activities was $730 million for the three months ended March 31, 2026, compared to cash used in financing activities of ($408) million for the three months ended March 31, 2025. The change primarily relates to long-term debt and changes in short-term borrowings. Debt issuances and redemptions or repayments vary each year. For the three months ended March 31, 2026, these activities reflect the impact of debt transactions associated with the acquisition of Calpine. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Quarterly dividends declared by our Board of Directors during 2026 were as follows:

Period

Declaration Date

Shareholder of Record Date

Dividend Payable Date

Cash per Share

First Quarter of 2026

February 20, 2026

March 9, 2026

March 20, 2026

0.4265

Second Quarter of 2026

April 28, 2026

May 15, 2026

June 5, 2026

0.4265

Credit Matters and Cash Requirements

We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets and large, diversified credit facilities. As of March 31, 2026, we have access to facilities with aggregate bank commitments of $15.1 billion. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

We had access to the commercial paper markets and had availability under our revolving credit facilities during the first quarter of 2026 to fund our short-term liquidity needs, when necessary. We routinely review the sufficiency of our liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. We closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS of our 2025 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

We believe our cash flow from operating activities, access to credit markets and our credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.

Security Ratings

Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our securities ratings. A loss of investment grade credit rating would have required a three-notch downgrade by S&P or Moody's from their current levels as of March 31, 2026 of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of March 31, 2026, we had $6.7 billion of available capacity under our credit facilities and $0.8 billion of cash on hand. In the event of a credit downgrade below investment grade and a resulting requirement to provide incremental collateral exceeding available capacity under our credit facilities and cash on hand, we would be required to access additional liquidity through the capital markets. Our borrowings are not subject to default or prepayment as a result of a downgrade of our securities, although such a downgrade could increase fees and interest charges under our credit agreements. Our credit ratings were affirmed by Moody’s and S&P in January 2026 following the completion of the acquisition of Calpine.

If we had lost our investment grade credit ratings as of March 31, 2026, we would have been required to provide incremental collateral estimated to be approximately $3.0 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements.

See Note 12 — Derivative Financial Instruments and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Table of Contents

Pension and Other Postretirement Benefits

We consider various factors when making qualified pension funding decisions, including actuarially-determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively) and at-risk status (which triggers higher minimum contribution requirements and participant notification). The contributions below reflect a funding strategy to make annual contributions to offset the growth of the liability. Based on this funding strategy and current market conditions, which are both subject to change, our annual qualified pension contribution was made in February 2026 for $161 million. Unlike the qualified pension plans, our non-qualified plans are not subject to statutory minimum contribution requirements.

OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded a portion of our plans. Annually, we evaluate whether additional funding for those plans is needed. For our funded OPEB plans, we consider several factors in determining the level of our contributions, including liabilities management and levels of benefit claims paid. The estimated benefit payments to the non-qualified pension plans in 2026 are approximately $25 million and the planned contributions to the OPEB plans, including estimated benefit payments to unfunded plans, are $64 million. Expected contributions in 2026 or future years could be affected by adjustments in our pension and OPEB funding strategy, market conditions, or pension regulation changes. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2025 Form 10-K for additional information on pension and other postretirement benefits.

Cash Requirements for Other Financial Commitments

In connection with the acquisition of Calpine in January 2026, we assumed approximately $3 billion of projected cash payments under existing financial commitments with fixed or minimum payments required. These commitments exclude future cash payments for debt service on assumed debt as much of the debt was refinanced or paid off following the acquisition. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Other than as described above and elsewhere in this Quarterly Report on Form 10-Q, there have been no material changes to the cash requirements from contractual and other obligations disclosed in our 2025 Annual Report on Form 10-K. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2025 Form 10-K for additional information on our cash requirements for financial commitments.

Accounts Receivable Facilities

We have an accounts receivable financing facility that provides us access to revolving loans from a number of financial institutions secured by certain accounts receivables. As a result of our acquisition of Calpine in January 2026, we assumed Calpine's accounts receivable sales program which allows for the sale of certain Calpine receivables at a nominal discount. See Note 7 — Accounts Receivable and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Project Financing

Project financing is based upon a financial structure in which project debt is paid back from the cash generated by a specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. If a project financing entity does not maintain compliance with its specific debt covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment were not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to repay the debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. As a result of our acquisition of Calpine in January 2026, we assumed various project financing arrangements. See Note 16 — Debt and Credit Agreements of our 2025 Form 10-K and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on project finance credit facilities and nonrecourse debt.

Table of Contents

Credit Facilities

We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. We assumed various credit facilities as part of the acquisition of Calpine. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities.

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts for radiological decommissioning of the facility. These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding the latest funding status report filed with the NRC.

As of March 31, 2026, the Crane NDT is fully funded under the SAFSTOR scenario that was the planned decommissioning option, as described in the Crane PSDAR filed with the NRC in April 2019. We will continue to file Crane's decommissioning funding status with the NRC annually until restart, at which point we will file decommissioning funding status reports in accordance with applicable NRC requirements. Additionally, as of March 31, 2026, we have adequate NDT funds for the remaining radiological decommissioning costs at Zion Station related to the Independent Spent Fuel Storage Installation. Decommissioning costs other than radiological may require funding from us. See Liquidity and Capital Resources — NRC Minimum Funding Requirements of our 2025 Form 10-K for information regarding the risk of additional financial assurance for shutdown units.

Properties

There have been no changes in the properties that were owned as of December 31, 2025 and disclosed within ITEM 2. PROPERTIES of our 2025 Form 10-K. The following table presents our interests in net electric generating capacity by station as of March 31, 2026, for those acquired from Calpine.

Station

Location

No. of Units

Percent Owned(a)

Primary Fuel Type

Primary Dispatch Type(b)

Net Generation Capacity (MWs)(c)

Calpine

Deer Park

Deer Park, TX

Gas

Intermediate

1,217

Bethlehem(d)

Bethlehem, PA

Gas

Intermediate

1,130

Hay Road(d)

Wilmington, DE

Gas

Intermediate

1,130

Guadalupe

New Braunfels, TX

Gas

Intermediate

1,040

Greenfield

Ontario, Canada

Gas

Intermediate

1,088

Baytown

Baytown, TX

Gas

Intermediate

896

Delta

Pittsburg, CA

Gas

Intermediate

882

Channel

Houston, TX

Gas

Intermediate

845

York 2(d)

Delta, PA

Gas

Intermediate

828

Morgan

Decatur, AL

Gas

Intermediate

807

Thad Hill

Clifton, TX

Gas

Intermediate

792

Pasadena

Pasadena, TX

Gas

Intermediate

781

Freestone

Fairfield, TX

Gas

Intermediate

776

Pastoria

Arvin, CA

Gas

Intermediate

759

Magic Valley

Edinburg, TX

Gas

Intermediate

712

Table of Contents

Station

Location

No. of Units

Percent Owned(a)

Primary Fuel Type

Primary Dispatch Type(b)

Net Generation Capacity (MWs)(c)

Granite Ridge

Londonderry , NH

Gas

Intermediate

695

Hermiston

Hermiston, OR

Gas

Intermediate

635

Metcalf

Coyote, CA

Gas

Intermediate

625

Russell City

Hayward, CA

Gas

Intermediate

619

Jack A. Fusco(d)

Richmond, TX

Gas

Intermediate

609

Otay Mesa

San Diego, CA

Gas

Intermediate

608

Sutter

Yuba City, CA

Gas

Intermediate

578

Los Medanos

Pittsburg, CA

Gas

Intermediate

572

York 1(d)

Delta, PA

Gas

Intermediate

565

South Point

Mohave Valley, AZ

Gas

Intermediate

555

Westbrook

Westbrook, ME

Gas

Intermediate

552

Quail Run

Odessa, TX

Gas

Intermediate

550

Corpus Christi

Corpus Christi, TX

Gas

Intermediate

520

Texas City

Texas City, TX

Gas

Intermediate

453

Hidalgo

Edinburg, TX

78.5

Gas

Intermediate

395

Los Esteros

San Jose, CA

Gas

Intermediate

309

Pine Bluff

Pine Bluff, AR

Gas

Intermediate

215

Gilroy Cogeneration

Gilroy, CA

Gas

Intermediate

130

King City Cogeneration

King City, CA

Gas

Intermediate

120

Bethpage 3

Levittown, NY

Gas

Intermediate

Bethpage

Bethpage, NY

Gas

Intermediate

Stony Brook

Stony Brook, NY

Gas

Intermediate

Agnews

San Jose, CA

Gas

Intermediate

Zion

Zion, IL

Gas

Peaking

503

Cumberland

Milleville, NJ

Gas

Peaking

191

Gilroy

Gilroy, CA

Gas

Peaking

141

Sherman Avenue

Vineland, NJ

Gas

Peaking

Wolfskill

Fairfield, CA

Gas

Peaking

Bethpage Peaker

Bethpage, NY

Gas

Peaking

Yuba City

Yuba City, CA

Gas

Peaking

Feather River

Yuba City, CA

Gas

Peaking

Creed

Suisun City, CA

Gas

Peaking

Lambie

Suisun City, CA

Gas

Peaking

Goose Haven

Suisun City, CA

Gas

Peaking

Riverview

Antioch, CA

Gas

Peaking

King City Peaking

King City, CA

Gas

Peaking

Delaware City

New Castle, DE

Gas

Peaking

West

Wilmington, DE

Gas

Peaking

Fore River

Weymouth, MA

Oil/Gas

Intermediate

731

Edge Moor(d)

Wilmington, DE

Oil

Peaking

725

Christiana

Wilmington, DE

Oil

Peaking

Tasley

Accomac, VA

Oil

Peaking

Bayview

Cape Charles, VA

Oil

Peaking

Crisfield

Crisfield, MD

Oil

Peaking

Table of Contents

Station

Location

No. of Units

Percent Owned(a)

Primary Fuel Type

Primary Dispatch Type(b)

Net Generation Capacity (MWs)(c)

Nova Project I-V

Menifee, CA

Battery Storage

Peaking

680

Santa Ana

Santa Ana, CA

Battery Storage

Peaking

West Ford Flat

Sonoma County, CA

Battery Storage

Peaking

Bear Canyon

Sonoma County, CA

Battery Storage

Peaking

McCabe 5 & 6

Sonoma County, CA

Geothermal

Baseload

Ridge Line 7 & 8

Sonoma County, CA

Geothermal

Baseload

Eagle Rock

Sonoma County, CA

Geothermal

Baseload

Calistoga

Lake County, CA

Geothermal

Baseload

Big Geysers

Lake County, CA

Geothermal

Baseload

Lake View

Sonoma County, CA

Geothermal

Baseload

Quicksilver

Lake County, CA

Geothermal

Baseload

Sonoma

Sonoma County, CA

Geothermal

Baseload

Cobb Creek

Sonoma County, CA

Geothermal

Baseload

Socrates

Sonoma County, CA

Geothermal

Baseload

Sulphur Springs

Sonoma County, CA

Geothermal

Baseload

Grant

Sonoma County, CA

Geothermal

Baseload

Aidlin

Sonoma County, CA

Geothermal

Baseload

Vineland Solar

Vineland, NJ

Solar

Intermittent

Total Calpine

27,689

__________

(a)100%, unless otherwise indicated.

(b)Baseload units are those that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are those with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are those that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods.

(c)Net generation capacity is stated at proportionate ownership share. All facilities reflect a summer rating.

(d)These stations are pending divestiture as part of the regulatory requirements for the acquisition of Calpine that closed in January 2026 and the associated balances are classified as Assets held for sale in the Consolidated Balance Sheets. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies, or generating units being temporarily out of service for inspection, maintenance, refueling, repairs, or modifications required by regulatory authorities.

Table of Contents

The following table presents our estimated net generation capacity by station for projects under construction at March 31, 2026, each of which is wholly owned by us unless otherwise noted.

Station

Location

No. of Units

Primary Fuel Type

Primary Dispatch Type

Estimated Net Generation Capacity (MWs)(a)

Crane

Middletown, PA

Uranium

Baseload

835

Pin Oak Creek(b)

Freestone, TX

Gas

Peaking

425

Pastoria Solar(c)

Kern County, CA

Solar

Intermittent

105

Pastoria/Bess

Kern County, CA

Battery Storage

Peaking

Total Projects Under Construction

1,445

__________

(a)The estimated net generation capacity for units under construction is approximate until commercial operation commences and applicable confirmatory testing is completed.

(b)Commercial operation was in April 2026. Additionally, in May 2026, we sold a 25% ownership interest in the facility to an unrelated party. The sale did not have a material impact on our results of operations or financial condition.

(c)Pastoria Solar was commissioned in April 2026.


ITEM 3.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

(Dollars in millions, unless otherwise noted)

We are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. We manage these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The Executive Committee and the Audit and Risk Committee of the Board of Directors have oversight responsibilities for risk management. The following discussion serves as an update to ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of our 2025 Annual Report on Form 10-K incorporated herein by reference.

Commodity Price Risk

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental, regulatory and environmental policies, and other factors. To the extent the total amount of energy we produce or procure differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in commodity prices. We seek to mitigate our commodity price risk through the sale and purchase of electricity, natural gas and oil, and other commodities.

Electricity available from our owned or contracted generation supply in excess of our obligations to customers is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, we enter into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures in locations and periods where our load serving activities do not naturally offset existing generation portfolio risk. Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation. We expect the settlement of the majority of our economic hedges will occur during 2026 through 2028. We also enter into transactions that further optimize the economic benefits of our overall portfolio.

The forecasted market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure as of March 31, 2026 for our portfolio associated with a hypothetical $10/MWh reduction in the annual average around-the-clock energy price and $5/MWh reduction in around-the-clock spark spread results in an impact to earnings that is not material for 2026 and 2027. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Table of Contents

Fuel Procurement

We procure natural gas through long-term and short-term contracts, and spot-market purchases. We also enter into natural gas transportation and storage contracts that allow us to source reliable and cost-effective natural gas for our fleet and to take advantage of favorable market pricing, regardless of when the gas is used in our operations. Fuel oil inventories are managed so that, in the winter months, sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.

Nuclear fuel is obtained predominantly through long-term contracts for uranium concentrates, conversion services, enrichment services, (or a combination thereof) and fabrication services, including contracts sourced from Russia. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make our procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. We engage a diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term. Approximately 35% of our uranium concentrate requirements for the remainder of 2026 through 2031 are supplied by three suppliers. To-date, we have not experienced any counterparty credit risk associated with these suppliers stemming from the Russia and Ukraine conflict. In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Geopolitical developments, including the Russia and Ukraine conflict and United States, United Kingdom, European Union, and Canadian sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium processing industry. Non-performance by these counterparties could have a material adverse impact on our consolidated financial statements. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Other Key Business Drivers for additional information on the Russia and Ukraine conflict.

Commodity Derivative Activity

The following table provides detail on changes in our commodity derivative contract net assets (liabilities) balance sheet position from December 31, 2025 to March 31, 2026. This table incorporates the unrealized gains and losses that are immediately recorded in earnings. This table excludes all NPNS contracts. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the commodity derivative contract net assets (liabilities) recorded as of March 31, 2026 and December 31, 2025.


Balance as of December 31, 2025(a)	$	504
Net change in fair value of contracts recorded in results of operations	1,294
Reclassification to realized at settlement of contracts recorded in results of operations	(235)
Changes in allocated collateral	(265)
Contracts acquired at acquisition date(b)	1,403
Amortization of acquired contracts(b)	(228)
Net option premium paid (received)	15
Option premium amortization	18
Upfront payments and amortizations(c)	(14)
Foreign currency translation	1
Balance as of March 31, 2026(a)	$	2,493

__________

(a)Amounts are shown net of collateral paid to and received from counterparties.

(b)Includes amounts related to contracts acquired as part of the Calpine acquisition in January 2026. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

(c)Includes derivative contracts acquired or sold through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.

Table of Contents

Fair Values

The following table presents maturity and source of fair value for commodity derivative contract net assets (liabilities). See Note 14 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.


	Maturities Within												Total Fair Value
	2026		2027		2028		2029		2030		2031 and Beyond
Commodity derivative contracts(a):
Actively quoted prices (Level 1)	$	51	$	5	$	(9)	$	(13)	$	1	$	—	$	35
Prices provided by external sources (Level 2)	54		206		23		1		1		—		285
Prices based on model or other valuation methods (Level 3)	545		474		416		177		109		452		2,173
Total	$	650	$	685	$	430	$	165	$	111	$	452	$	2,493

__________

(a)Amounts are shown net of collateral paid to and received from counterparties (and offset against derivative assets and liabilities) of $1,683 million at March 31, 2026.

Credit Risk

We would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk.

Credit-Risk-Related Contingent Features

As part of the normal course of business, we routinely enter into physically or financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. In accordance with the contracts and applicable law, if we are downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on our net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. See Note 12 — Derivative Financial Instruments and Note 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.

We sell output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on our consolidated financial statements. As market prices rise above or fall below contracted price levels, we are required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with us. To post collateral, we depend on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources — Credit Matters and Cash Requirements — Credit Facilities for additional information.

Table of Contents

RTOs and ISOs

We participate in all of the established wholesale energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, OIESO, and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs and ISOs in markets regulated by FERC. In these areas, power and related products are traded through bilateral agreements between buyers and sellers and in the energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no RTO or ISO to administer energy markets, electricity and related products are purchased and sold primarily through bilateral agreements. For activities administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member be shared by the remaining participants. Non-performance or non-payment by a major member of an RTO or ISO could result in a material adverse impact on our consolidated financial statements.

Exchange Traded Transactions

We enter into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange (each an Exchange and, collectively, Exchanges). The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk.

Interest Rate Risk

We use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. We may also utilize interest rate swaps to manage our interest rate exposure, including derivatives to lock in rate levels in anticipation of future financings. A hypothetical 50 basis points change in interest rates associated with unhedged variable-rate long-term debt and interest rate swaps would not have resulted in a material impact to our earnings for the three months ended March 31, 2026. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Equity Price Risk

We maintain trust funds, as required by the NRC, to fund the costs of decommissioning our nuclear plants. Our NDT funds are reflected at fair value in the Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate us for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the investment performance of the trust funds and periodically review asset allocations in accordance with our NDT fund investment policy.

A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would have resulted in a $1,072 million reduction in the fair value of our NDT trust assets as of March 31, 2026. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements and Liquidity and Capital Resources section of ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information.

Our employee benefit plan trusts also hold investments in equity and debt securities. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates of our 2025 Form 10-K for further information.

Table of Contents


ITEM 4.			CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

During the first quarter of 2026, our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in periodic reports that we file or submit with the SEC. These disclosure controls and procedures have been designed to ensure that (a) information relating to our consolidated subsidiaries, is accumulated and made known to our management, including our principal executive officer and principal financial officer, by other employees as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of March 31, 2026, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective to accomplish their objectives.

Changes in Internal Control Over Financial Reporting

We continually strive to improve our disclosure controls and procedures to enhance the quality of our financial reporting and to maintain dynamic systems that change as conditions warrant. During the first quarter of 2026, we completed the acquisition of Calpine and are in the process of integrating Calpine into our system of internal control over financial reporting. We anticipate that Calpine will be fully incorporated into our annual assessment of internal control over financial reporting for the fiscal year ending December 31, 2026. There have been no other changes in internal control over financial reporting that occurred during the first quarter of 2026 that have materially affected, or are reasonably likely to materially affect, any of our internal control over financial reporting.

Table of Contents

PART II. OTHER INFORMATION

(Dollars in millions except per share data, unless otherwise noted)


ITEM 1.			LEGAL PROCEEDINGS

We are parties to various lawsuits and regulatory proceedings in the ordinary course of business. For information regarding material lawsuits and proceedings, see Note 3 — Regulatory Matters and Note 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this report. Such descriptions are incorporated herein by these references.


ITEM 1A.			RISK FACTORS

At March 31, 2026, our risk factors were consistent with the risk factors described in our 2025 Form 10-K in ITEM 1A. RISK FACTORS which was inclusive of the risks related to the Calpine acquisition and its operations.


ITEM 2.			UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities (CEG Parent)

During 2026, our Board of Directors approved a $4.4 billion increase relative to the remaining authorized amount to repurchase our outstanding common stock. No other repurchase plans or programs have been authorized. As of the date of this filing, we have approximately $4.7 billion of remaining authority for repurchases. See Note 16 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information regarding our share repurchase program.

No share repurchases occurred under the program during the three months ended March 31, 2026.


ITEM 4.			MINE SAFETY DISCLOSURES

Not Applicable.


ITEM 5.			OTHER INFORMATION

Rule 10b5-1 Trading Plans

During the three months ended March 31, 2026, none of our directors or executive officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated any contract, instruction or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement" (as defined in Item 408 under Regulation S-K of the Exchange Act).

Table of Contents


ITEM 6.			EXHIBITS


Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Exchange Act.

Exhibit No.			Description
2 .1*			Agreement and Plan of Merger, dated as of January 10, 2025, by and among Calpine Corporation, CPN CS Holdco Corp., CPN CKS Corp., Constellation Energy Corporation, Cascade Transco Inc., Cascade Transco – 1, LLC and Volt Energy Holdings GP, LLC, solely in its capacity as the representative of the stockholders of Calpine Corporation (File No. 001-41137, Form 8-K dated January 13, 2025, Exhibit 2.1)

4 .1			Indenture, dated December 27, 2019, between Calpine Corporation and Wilmington Trust, National Association, as trustee (including Form of 5.125% Senior Note due 2028) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.1)

4.2			Indenture, dated August 10, 2020, between Calpine Corporation and Wilmington Trust, National Association, as trustee (including Form of 4.625% Senior Note due 2029) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.2)

4 .3			Indenture, dated August 10, 2020, between Calpine Corporation and Wilmington Trust, National Association, as trustee (including Form of 5.000% Senior Note due 2031) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.3)
4.4			Indenture, dated December 20, 2019, among Calpine Corporation, the guarantors party thereto from time to time and Wilmington Trust, National Association, as trustee (including Form of 4.500% Senior Secured Notes due 2028) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.4)

4 .5			First Supplemental Indenture, dated August 20, 2025, among Calpine Corporation, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.5)

4 .6			Indenture, dated December 16, 2020, among Calpine Corporation, the guarantors party thereto from time to time and Wilmington Trust, National Association, as trustee (including Form of 3.750% Senior Secured Notes due 2031) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.6)

4 .7			First Supplemental Indenture, dated August 20, 2025, among Calpine Corporation, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.7)

4 .8			Form of Constellation Energy Generation, LLC Floating Rate Senior Notes due January 8, 2028 (File No. 333-85496, Form 8-K dated January 8, 2026, Exhibit 4.1)

4.9			Form of Constellation Energy Generation, LLC 3.900% Senior Notes due January 8, 2028 (File No. 333-85496, Form 8-K dated January 8, 2026, Exhibit 4.2)

4.10			Form of Constellation Energy Generation, LLC 4.400% Senior Notes due January 15, 2031 (File No. 333-85496, Form 8-K dated January 8, 2026, Exhibit 4.3)

4 .11			Form of Constellation Energy Generation, LLC 5.875% Senior Notes due January 15, 2066 (File No. 333-85496, Form 8-K dated January 8, 2026, Exhibit 4.4 )

4.12			First Supplemental Indenture, dated as of January 15, 2026, among Calpine Corporation and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 15, 2026, Exhibit 4.1)

4.13			First Supplemental Indenture, dated as of January 15, 2026, among Calpine Corporation and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 15, 2026, Exhibit 4.2)

4.14			Second Supplemental Indenture, dated as of January 15, 2026, among Calpine Corporation, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 15, 2026, Exhibit 4.3)

Table of Contents


4.15			Form of New 2029 Senior Note (File No. 001-41137, Form 8-K dated January 15, 2026, Exhibit 4.4)

4.16			Form of New February 2031 Senior Note (File No. 001-41137, Form 8-K dated January 15, 2026, Exhibit 4.5)

4.17			Form of New March 2031 Senior Note (File No. 001-41137, Form 8-K dated January 15, 2026, Exhibit 4.6)

10.1**			Registration Rights Agreement, dated January 7, 2026, by and among Constellation Energy Corporation and the parties thereto from time to time (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.1)

10.2*			Credit Agreement, dated December 15, 2017, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto from time to time, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.2)

10.3*			Amendment No. 3 to Credit Agreement, dated August 2, 2023, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.3)

10.4*			Amendment No. 4 to Credit Agreement, dated June 6, 2024, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto, and Citibank, N.A., as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.4)

10.5*			2024 Incremental Term Loan Commitment Supplement, dated September 16, 2024, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto, and Citibank, N.A., as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.5)

10.6*			Amendment No. 5 to Credit Agreement, dated November 18, 2025, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto, and Citibank, N.A., as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.6)

10.7*			Credit Agreement, dated June 9, 2020, among Geysers Power Company, LLC, the guarantors party thereto, MUFG Bank, Ltd, as administrative agent, MUFG Union Bank, N.A., as first lien collateral agent, and the lenders and issuing banks parties thereto (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.7)

10.8*			Omnibus Amendment Agreement, dated November 9, 2021, among Geysers Power Company, LLC, the guarantors party thereto, MUFG Bank, Ltd, as administrative agent, MUFG Union Bank, N.A., as first lien collateral agent, and the lenders and issuing banks parties thereto (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.8)

10.9*			Second Omnibus Amendment Agreement, dated May 31, 2022, among Geysers Power Company, LLC, the guarantors party thereto, MUFG Bank, Ltd, as administrative agent, MUFG Union Bank, N.A., as first lien collateral agent, and the lenders and issuing banks parties thereto (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.9)

Table of Contents


Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act as to the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2026 filed by the following officers for the following registrants:

Exhibit No.			Description
31.1			Filed by Joseph Dominguez for Constellation Energy Corporation

31.2			Filed by Shane P. Smith for Constellation Energy Corporation

31.3			Filed by Joseph Dominguez for Constellation Energy Generation, LLC

31.4			Filed by Shane P. Smith for Constellation Energy Generation, LLC

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2026 filed by the following officers for the following registrants:

Exhibit No.			Description
32.1			Filed by Joseph Dominguez for Constellation Energy Corporation

32.2			Filed by Shane P. Smith for Constellation Energy Corporation

32.3			Filed by Joseph Dominguez for Constellation Energy Generation, LLC

32.4			Filed by Shane P. Smith for Constellation Energy Generation, LLC

Exhibit No.			Description
101.INS			Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH			Inline XBRL Taxonomy Extension Schema Document.

101.CAL			Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF			Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB			Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE			Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

__________

* Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. CEG Parent will furnish the omitted schedules to the SEC upon request by the SEC.

** Portions of this exhibit have been redacted in accordance with Item 601(a)(6) of Regulation S-K.

Table of Contents

SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CONSTELLATION ENERGY CORPORATION


/s/ JOSEPH DOMINGUEZ						/s/ SHANE P. SMITH
Joseph Dominguez						Shane P. Smith
President and Chief Executive Officer (Principal Executive Officer)						Executive Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ MATTHEW N. BAUER
Matthew N. Bauer
Senior Vice President and Controller (Principal Accounting Officer)

May 11, 2026

Table of Contents

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CONSTELLATION ENERGY GENERATION, LLC


/s/ JOSEPH DOMINGUEZ						/s/ SHANE P. SMITH
Joseph Dominguez						Shane P. Smith
President and Chief Executive Officer (Principal Executive Officer)						Executive Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ MATTHEW N. BAUER
Matthew N. Bauer
Senior Vice President and Controller (Principal Accounting Officer)

May 11, 2026

Constellation Energy - 10-Q quarterly report FY

What is the market capitalization of a company?

DISCLAIMER

Contact

Links