Murphy Oil - 10-Q quarterly report FY2019 Q3

Murphy Oil - 10-Q quarterly report FY2019 Q3

What is the market capitalization of a company?

DISCLAIMER

Contact

Links

false--12-31Q32019000071742308070487000894673100016050001605000111450000000450000000450000000195065341195076924195083364001001001004000004000004000000002201809532832771<div style="font-family:Times New Roman;font-size:10pt;"><div style="line-height:120%;padding-top:13px;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;font-weight:bold;">Subsequent Event</font></div></div>00007174232019-01-012019-09-3000007174232019-09-3000007174232018-12-3100007174232018-07-012018-09-3000007174232019-07-012019-09-3000007174232018-01-012018-09-3000007174232017-12-3100007174232018-09-300000717423us-gaap:ParentMember2018-09-300000717423us-gaap:RetainedEarningsMember2018-09-300000717423us-gaap:AdditionalPaidInCapitalMember2018-01-012018-09-300000717423us-gaap:AccumulatedOtherComprehensiveIncomeMember2018-01-012018-09-300000717423us-gaap:NoncontrollingInterestMember2019-07-012019-09-300000717423us-gaap:AdditionalPaidInCapitalMember2018-12-310000717423us-gaap:AdditionalPaidInCapitalMember2017-12-310000717423us-gaap:AdditionalPaidInCapitalMember2018-07-012018-09-300000717423us-gaap:AdditionalPaidInCapitalMember2019-07-012019-09-300000717423us-gaap:RetainedEarningsMember2019-07-012019-09-300000717423us-gaap:TreasuryStockMember2018-01-012018-09-300000717423us-gaap:RetainedEarningsMember2019-09-300000717423us-gaap:RetainedEarningsMember2019-01-012019-09-300000717423us-gaap:CommonStockMember2018-01-012018-09-300000717423us-gaap:NoncontrollingInterestMember2018-09-300000717423us-gaap:AdditionalPaidInCapitalMember2019-01-012019-09-300000717423us-gaap:PreferredStockMember2018-09-300000717423us-gaap:NoncontrollingInterestMember2018-01-012018-09-300000717423us-gaap:NoncontrollingInterestMember2019-06-300000717423us-gaap:NoncontrollingInterestMember2019-01-012019-09-300000717423us-gaap:CommonStockMember2018-09-300000717423us-gaap:TreasuryStockMember2018-07-012018-09-300000717423us-gaap:AccumulatedOtherComprehensiveIncomeMember2019-01-012019-09-300000717423us-gaap:AdditionalPaidInCapitalMember2019-09-300000717423us-gaap:NoncontrollingInterestMember2019-09-300000717423us-gaap:AccumulatedOtherComprehensiveIncomeMember2018-12-310000717423us-gaap:TreasuryStockMember2019-01-012019-09-300000717423us-gaap:NoncontrollingInterestMember2018-12-310000717423us-gaap:AccumulatedOtherComprehensiveIncomeMember2019-06-300000717423us-gaap:CommonStockMember2018-06-300000717423us-gaap:AccumulatedOtherComprehensiveIncomeMember2018-07-012018-09-300000717423us-gaap:NoncontrollingInterestMember2018-06-300000717423us-gaap:CommonStockMember2017-12-310000717423us-gaap:CommonStockMember2019-01-012019-09-300000717423us-gaap:RetainedEarningsMember2018-01-012018-09-300000717423us-gaap:RetainedEarningsMember2017-12-310000717423us-gaap:AdditionalPaidInCapitalMember2018-09-300000717423us-gaap:RetainedEarningsMember2018-07-012018-09-300000717423us-gaap:AccumulatedOtherComprehensiveIncomeMember2018-09-300000717423us-gaap:NoncontrollingInterestMember2018-07-012018-09-300000717423us-gaap:TreasuryStockMember2019-06-300000717423us-gaap:CommonStockMember2019-09-300000717423us-gaap:AccumulatedOtherComprehensiveIncomeMember2019-07-012019-09-300000717423us-gaap:TreasuryStockMember2019-07-012019-09-300000717423us-gaap:CommonStockMember2019-07-012019-09-300000717423us-gaap:AdditionalPaidInCapitalMember2019-06-300000717423us-gaap:RetainedEarningsMember2018-06-300000717423us-gaap:TreasuryStockMember2019-09-300000717423us-gaap:TreasuryStockMember2018-09-300000717423us-gaap:TreasuryStockMember2018-06-300000717423us-gaap:CommonStockMember2018-12-310000717423us-gaap:AccumulatedOtherComprehensiveIncomeMember2019-09-300000717423us-gaap:ParentMember2019-09-300000717423us-gaap:NoncontrollingInterestMember2017-12-310000717423us-gaap:AccumulatedOtherComprehensiveIncomeMember2018-06-300000717423us-gaap:TreasuryStockMember2018-12-310000717423us-gaap:PreferredStockMember2019-09-300000717423us-gaap:AccumulatedOtherComprehensiveIncomeMember2017-12-310000717423us-gaap:TreasuryStockMember2017-12-310000717423us-gaap:CommonStockMember2019-06-300000717423us-gaap:RetainedEarningsMember2018-12-310000717423us-gaap:AdditionalPaidInCapitalMember2018-06-300000717423us-gaap:RetainedEarningsMember2019-06-300000717423us-gaap:CommonStockMember2018-07-012018-09-3000007174232019-01-010000717423us-gaap:RetainedEarningsMember2019-01-012019-01-010000717423srt:NaturalGasReservesMembermur:CanadaOnshoreMember2018-07-012018-09-300000717423srt:OilReservesMembermur:CanadaOnshoreMember2019-01-012019-09-300000717423srt:NaturalGasLiquidsReservesMember2019-01-012019-09-300000717423srt:NaturalGasLiquidsReservesMembermur:UnitedStatesOffshoreMember2019-01-012019-09-300000717423srt:OilReservesMembermur:UnitedStatesOnshoreMember2018-01-012018-09-300000717423srt:NaturalGasLiquidsReservesMember2018-01-012018-09-300000717423srt:OilReservesMember2019-01-012019-09-300000717423srt:OilReservesMembermur:LocationsOtherThanUsCaAndMyMember2018-07-012018-09-300000717423srt:OilReservesMembermur:LocationsOtherThanUsCaAndMyMember2019-07-012019-09-300000717423srt:NaturalGasReservesMember2019-01-012019-09-300000717423srt:NaturalGasLiquidsReservesMember2019-07-012019-09-300000717423srt:NaturalGasReservesMembermur:UnitedStatesOnshoreMember2018-07-012018-09-300000717423srt:OilReservesMembermur:CanadaOffshoreMember2018-07-012018-09-300000717423srt:NaturalGasReservesMembermur:CanadaOnshoreMember2018-01-012018-09-300000717423srt:OilReservesMembermur:CanadaOffshoreMember2019-07-012019-09-300000717423srt:OilReservesMembermur:UnitedStatesOffshoreMember2018-07-012018-09-300000717423srt:NaturalGasLiquidsReservesMembermur:UnitedStatesOnshoreMember2018-01-012018-09-300000717423srt:NaturalGasLiquidsReservesMembermur:CanadaOnshoreMember2019-07-012019-09-300000717423srt:NaturalGasReservesMembermur:UnitedStatesOffshoreMember2019-01-012019-09-300000717423srt:NaturalGasLiquidsReservesMembermur:UnitedStatesOffshoreMember2018-01-012018-09-300000717423srt:NaturalGasLiquidsReservesMembermur:UnitedStatesOnshoreMember2019-01-012019-09-300000717423srt:OilReservesMembermur:CanadaOffshoreMember2019-01-012019-09-300000717423srt:NaturalGasReservesMembermur:UnitedStatesOnshoreMember2019-01-012019-09-300000717423srt:NaturalGasLiquidsReservesMembermur:CanadaOnshoreMember2018-01-012018-09-300000717423srt:NaturalGasLiquidsReservesMembermur:CanadaOnshoreMember2018-07-012018-09-300000717423srt:NaturalGasReservesMember2018-01-012018-09-300000717423srt:OilReservesMember2018-07-012018-09-300000717423srt:OilReservesMembermur:LocationsOtherThanUsCaAndMyMember2019-01-012019-09-300000717423srt:NaturalGasReservesMember2019-07-012019-09-300000717423srt:OilReservesMember2019-07-012019-09-300000717423srt:OilReservesMembermur:UnitedStatesOnshoreMember2019-01-012019-09-300000717423srt:NaturalGasReservesMember2018-07-012018-09-300000717423srt:NaturalGasReservesMembermur:UnitedStatesOnshoreMember2018-01-012018-09-300000717423srt:OilReservesMember2018-01-012018-09-300000717423srt:NaturalGasReservesMembermur:UnitedStatesOnshoreMember2019-07-012019-09-300000717423srt:OilReservesMembermur:UnitedStatesOnshoreMember2018-07-012018-09-300000717423srt:OilReservesMembermur:CanadaOnshoreMember2018-01-012018-09-300000717423srt:OilReservesMembermur:UnitedStatesOnshoreMember2019-07-012019-09-300000717423srt:OilReservesMembermur:CanadaOnshoreMember2019-07-012019-09-300000717423srt:OilReservesMembermur:UnitedStatesOffshoreMember2019-01-012019-09-300000717423srt:NaturalGasLiquidsReservesMember2018-07-012018-09-300000717423srt:NaturalGasReservesMembermur:UnitedStatesOffshoreMember2018-01-012018-09-300000717423srt:NaturalGasReservesMembermur:CanadaOnshoreMember2019-07-012019-09-300000717423srt:NaturalGasLiquidsReservesMembermur:CanadaOnshoreMember2019-01-012019-09-300000717423srt:NaturalGasReservesMembermur:UnitedStatesOffshoreMember2018-07-012018-09-300000717423srt:NaturalGasLiquidsReservesMembermur:UnitedStatesOffshoreMember2018-07-012018-09-300000717423srt:OilReservesMembermur:LocationsOtherThanUsCaAndMyMember2018-01-012018-09-300000717423srt:OilReservesMembermur:UnitedStatesOffshoreMember2018-01-012018-09-300000717423srt:NaturalGasLiquidsReservesMembermur:UnitedStatesOffshoreMember2019-07-012019-09-300000717423srt:NaturalGasLiquidsReservesMembermur:UnitedStatesOnshoreMember2019-07-012019-09-300000717423srt:OilReservesMembermur:CanadaOnshoreMember2018-07-012018-09-300000717423srt:OilReservesMembermur:CanadaOffshoreMember2018-01-012018-09-300000717423srt:NaturalGasLiquidsReservesMembermur:UnitedStatesOnshoreMember2018-07-012018-09-300000717423srt:NaturalGasReservesMembermur:CanadaOnshoreMember2019-01-012019-09-300000717423srt:OilReservesMembermur:UnitedStatesOffshoreMember2019-07-012019-09-300000717423srt:NaturalGasReservesMembermur:UnitedStatesOffshoreMember2019-07-012019-09-300000717423country:CAmur:UsdIndexPricingMembermur:EndDateQuarter42026Member2019-09-300000717423country:CAmur:UsdIndexPricingMembermur:EndDateQuarter42020Member2019-09-300000717423country:CAmur:AlbertaAecoFixedPriceMembermur:EndDateQuarter42020Member2019-09-300000717423country:CAmur:UsdIndexPricingMembermur:EndDateQuarter42021Member2019-09-300000717423country:CAmur:UsdIndexPricingMember2019-09-300000717423country:USmur:EndDateQuarter42021Member2019-09-300000717423country:CAmur:UsdIndexPricingMembermur:EndDateQuarter42024Member2019-09-300000717423mur:GulfofMexicoMember2019-09-300000717423country:BN2019-09-300000717423mur:MontneyNaturalGasFieldsMember2018-01-012018-12-310000717423mur:MontneyNaturalGasFieldsMember2018-12-310000717423mur:MalaysiaSubsidiariesMember2019-07-312019-07-310000717423country:US2019-09-300000717423country:VN2019-09-300000717423mur:MontneyNaturalGasFieldsMember2016-01-012016-12-310000717423mur:CanadianSubsidiaryMembermur:KaybobDuvernayLandsAlbertaMember2016-01-012016-12-310000717423mur:MalaysiaSubsidiariesMember2019-07-310000717423mur:CanadianSubsidiaryMembermur:AthabascaOilCorporationMember2016-01-012016-12-310000717423mur:MontneyNaturalGasFieldsMember2019-01-010000717423mur:CanadianSubsidiaryMembermur:AthabascaOilCorporationMember2019-09-300000717423mur:MontneyNaturalGasFieldsMember2018-01-012018-09-300000717423mur:CanadianSubsidiaryMembermur:PlacidMontneyLandsAlbertaMember2016-01-012016-12-310000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodOneMember2018-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodFourMember2018-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodThreeMember2019-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodFourMember2019-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodOneMember2019-01-012019-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodOneMember2019-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodTwoMember2018-01-012018-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodOneMember2018-01-012018-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodTwoMember2019-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodThreeMember2018-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodThreeMember2018-01-012018-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodTwoMember2019-01-012019-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodFourMember2019-01-012019-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodThreeMember2019-01-012019-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodFourMember2018-01-012018-09-300000717423us-gaap:AgingOfCapitalizedExploratoryWellCostsPeriodTwoMember2018-09-300000717423mur:MalaysiaSubsidiariesMember2019-01-012019-09-300000717423us-gaap:DiscontinuedOperationsHeldForSaleOrDisposedOfBySaleMember2019-09-300000717423us-gaap:DiscontinuedOperationsHeldForSaleOrDisposedOfBySaleMember2018-12-310000717423mur:NewTermCreditFacilityMember2019-09-300000717423mur:RevolvingCreditFacility2018Member2019-09-300000717423mur:RevolvingCreditFacility2018Memberus-gaap:LetterOfCreditMember2019-09-300000717423mur:RevolvingCreditFacility2018Member2019-01-012019-09-300000717423us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-07-012019-09-300000717423us-gaap:PensionPlansDefinedBenefitMember2018-07-012018-09-300000717423us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2018-07-012018-09-300000717423us-gaap:PensionPlansDefinedBenefitMember2019-07-012019-09-300000717423us-gaap:PensionPlansDefinedBenefitMember2018-01-012018-09-300000717423us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2019-01-012019-09-300000717423us-gaap:PensionPlansDefinedBenefitMember2019-01-012019-09-300000717423us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2018-01-012018-09-300000717423mur:TimeBasedRestrictedStockUnitsMembermur:NonEmployeeDirectorPlanMemberus-gaap:DirectorMember2019-02-012019-02-280000717423mur:LongTermIncentivePlanTwentyTwelveMember2019-09-300000717423mur:CashSettledRestrictedStockUnitsMember2019-02-012019-02-280000717423mur:TimeBasedRestrictedStockUnitsMember2019-01-012019-03-310000717423mur:TimeBasedRestrictedStockUnitsMember2019-02-012019-02-280000717423srt:MinimumMembermur:PerformanceBasedRestrictedStockUnitsMember2019-01-012019-03-310000717423mur:LongTermIncentivePlanTwentyTwelveMember2019-01-012019-09-300000717423mur:PerformanceBasedRestrictedStockUnitsMember2019-01-012019-03-310000717423us-gaap:CanadaRevenueAgencyMember2019-01-012019-09-300000717423us-gaap:CanadaRevenueAgencyMember2019-07-012019-09-300000717423us-gaap:CommodityContractMemberus-gaap:NondesignatedMembermur:GainLossOnCrudeContractsMember2019-07-012019-09-300000717423us-gaap:CommodityContractMemberus-gaap:NondesignatedMembermur:GainLossOnCrudeContractsMember2019-01-012019-09-300000717423us-gaap:CommodityContractMemberus-gaap:NondesignatedMembermur:GainLossOnCrudeContractsMember2018-07-012018-09-300000717423us-gaap:CommodityContractMemberus-gaap:NondesignatedMembermur:GainLossOnCrudeContractsMember2018-01-012018-09-300000717423us-gaap:CommodityContractMemberus-gaap:SubsequentEventMember2019-10-012019-10-300000717423us-gaap:InterestRateSwapMember2019-09-300000717423us-gaap:CommodityContractMember2019-01-012019-09-300000717423us-gaap:CommodityContractMemberus-gaap:SubsequentEventMember2020-01-012020-09-300000717423us-gaap:CommodityContractMember2018-09-300000717423us-gaap:CommodityContractMember2019-09-300000717423us-gaap:ScenarioForecastMember2019-07-012019-12-310000717423us-gaap:CommodityContractMember2018-01-012018-09-300000717423us-gaap:CommodityContractMemberus-gaap:SubsequentEventMember2019-10-300000717423mur:NotesDue2022Member2019-01-012019-09-300000717423us-gaap:CommodityContractMemberus-gaap:SubsequentEventMember2020-06-300000717423us-gaap:CommodityContractMemberus-gaap:AccountsPayableMemberus-gaap:NondesignatedMember2019-09-300000717423us-gaap:CommodityContractMemberus-gaap:AccountsReceivableMemberus-gaap:NondesignatedMember2018-12-310000717423us-gaap:FairValueMeasurementsRecurringMembermur:ContingentConsiderationMember2019-09-300000717423us-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:CommodityContractMember2018-12-310000717423us-gaap:FairValueMeasurementsRecurringMemberus-gaap:CommodityContractMember2019-09-300000717423us-gaap:FairValueMeasurementsRecurringMemberus-gaap:CommodityContractMember2018-12-310000717423us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMembermur:NonqualifiedEmployeeSavingsPlansMember2018-12-310000717423us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsRecurringMembermur:NonqualifiedEmployeeSavingsPlansMember2019-09-300000717423us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsRecurringMembermur:ContingentConsiderationMember2019-09-300000717423us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsRecurringMember2018-12-310000717423us-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMembermur:NonqualifiedEmployeeSavingsPlansMember2018-12-310000717423us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMember2018-12-310000717423us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsRecurringMembermur:ContingentConsiderationMember2018-12-310000717423us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:CommodityContractMember2018-12-310000717423us-gaap:FairValueMeasurementsRecurringMembermur:NonqualifiedEmployeeSavingsPlansMember2018-12-310000717423us-gaap:FairValueMeasurementsRecurringMembermur:ContingentConsiderationMember2018-12-310000717423us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:CommodityContractMember2019-09-300000717423us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsRecurringMember2019-09-300000717423us-gaap:FairValueMeasurementsRecurringMember2018-12-310000717423us-gaap:FairValueMeasurementsRecurringMember2019-09-300000717423us-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMembermur:ContingentConsiderationMember2018-12-310000717423us-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMembermur:NonqualifiedEmployeeSavingsPlansMember2019-09-300000717423us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMembermur:ContingentConsiderationMember2018-12-310000717423us-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMember2019-09-300000717423us-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMember2018-12-310000717423us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMembermur:ContingentConsiderationMember2019-09-300000717423us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:CommodityContractMember2019-09-300000717423us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMembermur:NonqualifiedEmployeeSavingsPlansMember2019-09-300000717423us-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMembermur:ContingentConsiderationMember2019-09-300000717423us-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:CommodityContractMember2019-09-300000717423us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMember2019-09-300000717423us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:CommodityContractMember2018-12-310000717423us-gaap:FairValueMeasurementsRecurringMembermur:NonqualifiedEmployeeSavingsPlansMember2019-09-300000717423us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsRecurringMembermur:NonqualifiedEmployeeSavingsPlansMember2018-12-310000717423us-gaap:AccumulatedNetGainLossFromDesignatedOrQualifyingCashFlowHedgesMember2019-01-012019-09-300000717423us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2019-01-012019-09-300000717423us-gaap:AccumulatedTranslationAdjustmentMember2018-12-310000717423us-gaap:AccumulatedNetGainLossFromDesignatedOrQualifyingCashFlowHedgesMember2019-09-300000717423us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2018-12-310000717423us-gaap:AccumulatedTranslationAdjustmentMember2019-09-300000717423us-gaap:AccumulatedTranslationAdjustmentMember2019-01-012019-09-300000717423us-gaap:AccumulatedNetGainLossFromDesignatedOrQualifyingCashFlowHedgesMember2018-12-310000717423us-gaap:AccumulatedDefinedBenefitPlansAdjustmentMember2019-09-300000717423us-gaap:OperatingSegmentsMembermur:OtherRegionsMembermur:OilAndGasExplorationAndProductionSegmentMember2018-01-012018-09-300000717423us-gaap:SegmentContinuingOperationsMember2019-01-012019-09-300000717423us-gaap:OperatingSegmentsMembermur:OilAndGasExplorationAndProductionSegmentMember2019-01-012019-09-300000717423us-gaap:OperatingSegmentsMembermur:OilAndGasExplorationAndProductionSegmentMember2018-01-012018-09-300000717423us-gaap:OperatingSegmentsMembercountry:CAmur:OilAndGasExplorationAndProductionSegmentMember2019-01-012019-09-300000717423us-gaap:SegmentDiscontinuedOperationsMember2018-01-012018-09-300000717423us-gaap:SegmentDiscontinuedOperationsMember2019-01-012019-09-300000717423us-gaap:CorporateNonSegmentMember2019-01-012019-09-300000717423us-gaap:OperatingSegmentsMembercountry:CAmur:OilAndGasExplorationAndProductionSegmentMember2018-01-012018-09-300000717423us-gaap:OperatingSegmentsMembercountry:USmur:OilAndGasExplorationAndProductionSegmentMember2019-01-012019-09-300000717423us-gaap:OperatingSegmentsMembermur:OtherRegionsMembermur:OilAndGasExplorationAndProductionSegmentMember2019-01-012019-09-300000717423us-gaap:CorporateNonSegmentMember2018-01-012018-09-300000717423us-gaap:OperatingSegmentsMembercountry:USmur:OilAndGasExplorationAndProductionSegmentMember2018-01-012018-09-300000717423us-gaap:SegmentContinuingOperationsMember2018-01-012018-09-300000717423us-gaap:OperatingSegmentsMembermur:OtherRegionsMembermur:OilAndGasExplorationAndProductionSegmentMember2018-07-012018-09-300000717423us-gaap:SegmentDiscontinuedOperationsMember2019-07-012019-09-300000717423us-gaap:SegmentContinuingOperationsMember2019-09-300000717423us-gaap:OperatingSegmentsMembermur:OtherRegionsMembermur:OilAndGasExplorationAndProductionSegmentMember2019-07-012019-09-300000717423us-gaap:OperatingSegmentsMembercountry:USmur:OilAndGasExplorationAndProductionSegmentMember2018-07-012018-09-300000717423us-gaap:CorporateNonSegmentMember2019-07-012019-09-300000717423us-gaap:OperatingSegmentsMembermur:OilAndGasExplorationAndProductionSegmentMember2019-09-300000717423us-gaap:CorporateNonSegmentMember2018-07-012018-09-300000717423us-gaap:SegmentDiscontinuedOperationsMember2018-07-012018-09-300000717423us-gaap:OperatingSegmentsMembermur:OilAndGasExplorationAndProductionSegmentMember2018-07-012018-09-300000717423us-gaap:OperatingSegmentsMembercountry:CAmur:OilAndGasExplorationAndProductionSegmentMember2019-07-012019-09-300000717423us-gaap:CorporateNonSegmentMember2019-09-300000717423us-gaap:OperatingSegmentsMembercountry:CAmur:OilAndGasExplorationAndProductionSegmentMember2018-07-012018-09-300000717423us-gaap:OperatingSegmentsMembermur:OilAndGasExplorationAndProductionSegmentMember2019-07-012019-09-300000717423us-gaap:OperatingSegmentsMembercountry:CAmur:OilAndGasExplorationAndProductionSegmentMember2019-09-300000717423us-gaap:OperatingSegmentsMembercountry:USmur:OilAndGasExplorationAndProductionSegmentMember2019-07-012019-09-300000717423us-gaap:OperatingSegmentsMembercountry:USmur:OilAndGasExplorationAndProductionSegmentMember2019-09-300000717423us-gaap:SegmentContinuingOperationsMember2018-07-012018-09-300000717423us-gaap:SegmentContinuingOperationsMember2019-07-012019-09-300000717423us-gaap:OperatingSegmentsMembermur:OtherRegionsMembermur:OilAndGasExplorationAndProductionSegmentMember2019-09-300000717423us-gaap:SegmentDiscontinuedOperationsMember2019-09-300000717423us-gaap:AssetRetirementObligationCostsMember2019-07-012019-09-300000717423us-gaap:OtherOperatingIncomeExpenseMember2019-07-012019-09-300000717423us-gaap:SellingGeneralAndAdministrativeExpensesMember2019-01-012019-09-300000717423us-gaap:PropertyPlantAndEquipmentMember2019-01-012019-09-300000717423us-gaap:PropertyPlantAndEquipmentMember2019-07-012019-09-300000717423us-gaap:SellingGeneralAndAdministrativeExpensesMember2019-07-012019-09-300000717423us-gaap:OtherOperatingIncomeExpenseMember2019-01-012019-09-300000717423us-gaap:AssetRetirementObligationCostsMember2019-01-012019-09-300000717423srt:MinimumMember2019-01-012019-09-300000717423srt:MaximumMember2019-01-012019-09-300000717423us-gaap:OperatingExpenseMember2019-07-012019-09-300000717423us-gaap:OperatingExpenseMember2019-01-012019-09-300000717423mur:PetrobasAmericaIncMember2018-12-012018-12-310000717423mur:LLOGExplorationOffshoreL.L.C.andLLOGBluewaterHoldingsL.L.C.Member2018-12-012018-12-310000717423mur:PetrobasAmericaIncMember2018-12-310000717423mur:LLOGExplorationOffshoreL.L.C.andLLOGBluewaterHoldingsL.L.C.Member2018-12-310000717423mur:PetrobasAmericaIncMember2018-01-012018-09-300000717423mur:PetrobasAmericaIncMember2018-07-012018-09-300000717423mur:LLOGExplorationOffshoreL.L.C.andLLOGBluewaterHoldingsL.L.C.Member2019-07-012019-09-300000717423mur:LLOGExplorationOffshoreL.L.C.andLLOGBluewaterHoldingsL.L.C.Member2019-05-310000717423mur:PetrobasAmericaIncMembermur:MpGulfOfMexicoLlcMember2018-12-310000717423mur:PetrobasAmericaIncMember2019-01-012019-09-300000717423mur:MpGulfOfMexicoLlcMember2018-12-310000717423mur:LLOGExplorationOffshoreL.L.C.andLLOGBluewaterHoldingsL.L.C.Member2019-01-012019-09-300000717423mur:LLOGExplorationOffshoreL.L.C.andLLOGBluewaterHoldingsL.L.C.Member2019-06-012019-06-300000717423mur:PetrobasAmericaIncMembermur:PriceAndProductionThresholdsMember2018-12-310000717423mur:LLOGExplorationOffshoreL.L.C.andLLOGBluewaterHoldingsL.L.C.Membersrt:OilReservesMember2019-09-300000717423mur:LLOGExplorationOffshoreL.L.C.andLLOGBluewaterHoldingsL.L.C.Membermur:PriceAndProductionThresholdsMember2019-09-300000717423mur:PetrobasAmericaIncMember2019-07-012019-09-30mur:itemmur:wellutreg:MMcfutreg:Dmur:entityiso4217:USDxbrli:purexbrli:sharesiso4217:USDxbrli:sharesmur:segmentmur:projectutreg:Boeutreg:Dmur:OffsettingPositionutreg:bblutreg:Diso4217:USDutreg:bblutreg:MMBoemur:barrels_per_daymur:contractmur:Acquisition

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, 2019



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

For the transition period from to

Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)



Delaware		71-0361522
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)
300 Peach Street, P.O. Box 7000		71731-7000
El Dorado,	Arkansas	(Zip Code)
(Address of principal executive offices)
(870)		862-6411
(Registrant’s telephone number, including area code)

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



Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, $1.00 Par Value	MUR	New York Stock Exchange

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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.



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

Number of shares of Common Stock, $1.00 par value, outstanding at September 30, 2019 was 157,230,034.

Table of Contents

MURPHY OIL CORPORATION

TABLE OF CONTENTS



	Page
Part I – Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets	2
Consolidated Statements of Operations	3
Consolidated Statements of Comprehensive Income	4
Consolidated Statements of Cash Flows	5
Consolidated Statements of Stockholders’ Equity	6
Notes to Consolidated Financial Statements	7
Note A – Nature of Business and Interim Financial Statements	7
Note B – New Accounting Principles and Recent Accounting Pronouncements	7
Note C – Revenue from Contracts with Customers	8
Note D – Property, Plant, and Equipment	11
Note E – Discontinued Operations and Assets Held for Sale	12
Note F – Financing Arrangements and Debt	13
Note G – Other Financial Information	14
Note H – Employee and Retiree Benefit Plans	14
Note I – Incentive Plans	15
Note J – Earnings Per Share	16
Note K – Income Taxes	16
Note L – Financial Instruments and Risk Management	17
Note M – Accumulated Other Comprehensive Loss	19
Note N – Environmental and Other Contingencies	19
Note O – Business Segments	20
Note P – Leases	22
Note Q – Acquisitions	24
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3. Quantitative and Qualitative Disclosures About Market Risk	37
Item 4. Controls and Procedures	37
Part II – Other Information	38
Item 1. Legal Proceedings	38
Item 1A. Risk Factors	38
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 6. Exhibits	38
Signature	39

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS (unaudited)

(Thousands of dollars)



	September 30, 2019			December 31, 2018 ¹
ASSETS
Current assets
Cash and cash equivalents	$	434,899		359,923
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2019 and 2018	462,513			231,686
Inventories	79,441			80,024
Prepaid expenses	39,358			34,316
Assets held for sale	128,415			173,865
Total current assets	1,144,626			879,814
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $8,946,731 in 2019 and $8,070,487 in 2018	9,931,963			8,432,133
Operating lease assets	565,987			—
Deferred income taxes	94,592			146,197
Deferred charges and other assets	46,499			49,435
Non-current assets held for sale	—			1,545,008
Total assets	$	11,783,667		11,052,587
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	—		668
Accounts payable	575,461			348,026
Income taxes payable	18,658			15,309
Other taxes payable	27,454			17,649
Operating lease liabilities	117,071			—
Other accrued liabilities	176,102			177,948
Liabilities associated with assets held for sale	18,114			286,458
Total current liabilities	932,860			846,058
Long-term debt, including capital lease obligation	2,779,228			3,109,318
Asset retirement obligations	836,537			752,519
Deferred credits and other liabilities	551,793			624,436
Non-current operating lease liabilities	457,206			—
Deferred income taxes	200,223			129,894
Non-current liabilities associated with assets held for sale	—			392,720
Total liabilities	5,757,847			5,854,945
Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued	—			—
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,083,364 shares in 2019 and 195,076,924 shares in 2018	195,083			195,077
Capital in excess of par value	941,309			979,642
Retained earnings	6,726,316			5,513,529
Accumulated other comprehensive loss	(562,827		)	(609,787	)
Treasury stock	(1,623,231		)	(1,249,162	)
Murphy Shareholders' Equity	5,676,650			4,829,299
Noncontrolling interest	349,170			368,343
Total equity	6,025,820			5,197,642
Total liabilities and equity	$	11,783,667		11,052,587

¹Reclassified to conform to current presentation (see Note A). See Notes to Consolidated Financial Statements, page 7.

Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(Thousands of dollars, except per share amounts)



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018 ¹		2019		2018 ¹
Revenues
Revenue from sales to customers	$	750,337		475,458		2,060,127		1,330,399
Gain (loss) on crude contracts	63,247			(2,223	)	121,163		(69,349	)
Gain on sale of assets and other income	3,493			17,276		10,283		26,713
Total revenues	817,077			490,511		2,191,573		1,287,763
Costs and expenses
Lease operating expenses	147,632			83,751		416,460		253,820
Severance and ad valorem taxes	13,803			15,066		36,972		40,099
Transportation, gathering and processing	54,305			16,945		128,748		49,827
Exploration expenses, including undeveloped lease amortization	12,358			21,723		75,570		69,350
Selling and general expenses	55,366			60,683		176,258		165,074
Depreciation, depletion and amortization	325,562			197,503		819,270		570,997
Accretion of asset retirement obligations	10,587			6,466		29,824		19,234
Other expense (benefit)	(29,000		)	(34,386	)	26,442		(44,773	)
Total costs and expenses	590,613			367,751		1,709,544		1,123,628
Operating income from continuing operations	226,464			122,760		482,029		164,135
Other income (loss)
Interest and other income (loss)	(4,418		)	(4,583	)	(18,134	)	(713	)
Interest expense, net	(44,930		)	(44,209	)	(145,095	)	(133,075	)
Total other loss	(49,348		)	(48,792	)	(163,229	)	(133,788	)
Income (loss) from continuing operations before income taxes	177,116			73,968		318,800		30,347
Income tax expense (benefit)	18,782			17,837		38,719		(91,180	)
Income (loss) from continuing operations	158,334			56,131		280,081		121,527
Income from discontinued operations, net of income taxes	953,368			37,812		1,027,632		186,188
Net income including noncontrolling interest	1,111,702			93,943		1,307,713		307,715
Less: Net income attributable to noncontrolling interest	22,700			—		86,257		—
NET INCOME ATTRIBUTABLE TO MURPHY	$	1,089,002		93,943		1,221,456		307,715
INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations	$	0.85		0.32		1.16		0.70
Discontinued operations	5.94			0.22		6.14		1.08
Net Income	$	6.79		0.54		7.30		1.78

INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	$	0.84		0.32		1.16		0.70
Discontinued operations	5.92			0.22		6.11		1.07
Net Income	$	6.76		0.54		7.27		1.77

Cash dividends per Common share	0.25			0.25		0.75		0.75

Average Common shares outstanding (thousands)
Basic	160,366			173,047		167,310		172,949
Diluted	160,980			174,175		168,105		174,202

¹ Reclassified to conform to current presentation (see Note A). See Notes to Consolidated Financial Statements, page 7.

Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019			2018	2019	2018

Net income	$	1,089,002		93,943	1,221,456	307,715
Other comprehensive income (loss), net of tax
Net (loss) gain from foreign currency translation	(17,128		)	33,380	36,927	(53,805	)
Retirement and postretirement benefit plans	2,761			3,390	8,277	10,498
Deferred loss on interest rate hedges reclassified to interest expense	585			585	1,756	1,756
Reclassification of certain tax effects to retained earnings	—			—	—	(30,237	)
Other	—			—	—	(3,737	)
Other comprehensive income (loss)	(13,782		)	37,355	46,960	(75,525	)
COMPREHENSIVE INCOME	$	1,075,220		131,298	1,268,416	232,190

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)



	Nine Months Ended September 30,
	2019			2018 ¹
Operating Activities
Net income including noncontrolling interest	$	1,307,713		307,715
Adjustments to reconcile net income to net cash provided by continuing operations activities:
(Income) loss from discontinued operations	(1,027,632		)	(186,188	)
Depreciation, depletion and amortization	819,270			570,997
Previously suspended exploration costs (credits)	12,901			4,514
Amortization of undeveloped leases	21,680			31,544
Accretion of asset retirement obligations	29,824			19,234
Deferred income tax charge (benefit)	50,597			(134,393	)
Pretax (gain) loss from sale of assets	(363		)	(6	)
Mark to market and revaluation of contingent consideration	512			—
Mark to market of crude contracts	(100,076		)	1,065
Long-term non-cash compensation	60,567			52,309
Net (increase) decrease in noncash operating working capital	40,257			(9,501	)
Other operating activities, net	(62,023		)	(55,924	)
Net cash provided by continuing operations activities	1,153,227			601,366
Investing Activities
Acquisition of oil and gas properties	(1,212,949		)	—
Property additions and dry hole costs	(1,009,146		)	(797,630	)
Proceeds from sales of property, plant and equipment	19,072			921
Net cash required by investing activities	(2,203,023		)	(796,709	)
Financing Activities
Borrowings on revolving credit facility and term loan	1,575,000			—
Repayment of revolving credit facility and term loan	(1,900,000		)	—
Repurchase of common stock	(405,938		)	—
Capital lease obligation payments	(510		)	(154	)
Withholding tax on stock-based incentive awards	(6,991		)	(6,922	)
Distribution to noncontrolling interest	(97,510		)	—
Cash dividends paid	(125,437		)	(129,780	)
Net cash provided (required) by financing activities	(961,386		)	(136,856	)
Cash Flows from Discontinued Operations ²
Operating activities	74,361			370,343
Investing activities	1,985,202			(60,715	)
Financing activities	(4,914		)	(7,013	)
Net cash provided by discontinued operations	2,054,649			302,615
Cash transferred from discontinued operations to continuing operations	2,083,565			536,492
Effect of exchange rate changes on cash and cash equivalents	2,593			13,107
Net increase (decrease) in cash and cash equivalents	74,976			217,400
Cash and cash equivalents at beginning of period	359,923			630,433
Cash and cash equivalents at end of period	$	434,899		847,833

¹ Reclassified to conform to current presentation (See Note A).

² Net cash provided by discontinued operations are not part of the cash flow reconciliation.

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019		2018
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued	$	—		—		—		—
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,083,364 shares at September 30, 2019 and 195,065,341 shares at September 30, 2018
Balance at beginning of period	195,083			195,065		195,077		195,056
Exercise of stock options	—			—		6		9
Balance at end of period	195,083			195,065		195,083		195,065
Capital in Excess of Par Value
Balance at beginning of period	933,944			898,126		979,642		917,665
Exercise of stock options, including income tax benefits	—			—		(123	)	(175	)
Restricted stock transactions and other	—			—		(38,732	)	(32,766	)
Stock-based compensation	7,365			7,253		25,041		20,655
Adjustments to acquisition valuation	—			—		(24,519	)	—
Balance at end of period	941,309			905,379		941,309		905,379
Retained Earnings
Balance at beginning of period	5,677,248			5,402,734		5,513,529		5,245,242
Net income (loss) for the period	1,089,002			93,943		1,221,456		307,715
Reclassification of certain tax effects from accumulated other comprehensive loss	—			—		—		30,237
Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact	—			—		116,768		—
Cash dividends	(39,934		)	(43,263	)	(125,437	)	(129,780	)
Balance at end of period	6,726,316			5,453,414		6,726,316		5,453,414
Accumulated Other Comprehensive Loss
Balance at beginning of period	(549,045		)	(575,123	)	(609,787	)	(462,243	)
Foreign currency translation (loss) gain, net of income taxes	(17,128		)	33,380		36,927		(53,805	)
Retirement and postretirement benefit plans, net of income taxes	2,761			3,390		8,277		10,498
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes	585			585		1,756		1,756
Reclassification of certain tax effects to retained earnings	—			—		—		(30,237	)
Other	—			—		—		(3,737	)
Balance at end of period	(562,827		)	(537,768	)	(562,827	)	(537,768	)
Treasury Stock
Balance at beginning of period	(1,517,217		)	(1,249,162	)	(1,249,162	)	(1,275,529	)
Purchase of treasury shares	(106,014		)	—		(405,938	)	—
Awarded restricted stock, net of forfeitures	—			—		31,869		26,367
Balance at end of period – 37,853,330 shares of Common Stock in 2019 and 22,018,095 shares of Common Stock in 2018, at cost	(1,623,231		)	(1,249,162	)	(1,623,231	)	(1,249,162	)
Murphy Shareholders’ Equity	5,676,650			4,766,928		5,676,650		4,766,928
Noncontrolling Interest
Balance at beginning of period	358,531			—		368,343		—
Acquisition closing adjustments	(3,328		)	—		(7,920	)	—
Net income attributable to noncontrolling interest	22,700			—		86,257		—
Distributions to noncontrolling Interest Owners	(28,733		)	—		(97,510	)	—
Balance at end of period	349,170			—		349,170		—
Total Equity	$	6,025,820		4,766,928		6,025,820		4,766,928

See Notes to Consolidated Financial Statements, page 7.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 2 through 6 of this Form 10-Q report.

Note A – Nature of Business and Interim Financial Statements

NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the United States and Canada and conducts oil and natural gas exploration activities worldwide.

Effective January 1, 2019, Malaysia was reported as discontinued operations as the sale represents a strategic shift that has a major effect on the Company’s operations and financial results. Prior periods have been reclassified to conform with the current presentation. See Note D – Property, Plant, and Equipment and Note E – Discontinued Operations and Assets Held for Sale for more information regarding the sale of this asset.

In connection with the LLOG acquisition, further discussed in Note Q – Acquisitions, we now hold a 0.5% interest in two variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House FPS LLC (collectively Delta House). These VIEs have not been consolidated because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of September 30, 2019, our maximum exposure to loss was $3.7 million, which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.

INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at September 30, 2019 and December 31, 2018, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2019 and 2018, in conformity with accounting principles generally accepted in the United States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2018 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and nine-month periods ended September 30, 2019 are not necessarily indicative of future results.

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

Leases. In February 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) 2016-02 (Topic 842) to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The company adopted the standard in the first quarter of 2019 utilizing the modified retrospective transition method through a cumulative-effect adjustment at the beginning of the first quarter of 2019. The Company has elected the package of practical expedients, which allows the Company not to reassess (1) whether any expired or existing contracts as of the adoption date are or contain a lease, (2) lease classification for any expired or existing leases as of the adoption date and (3) initial direct costs for any existing leases as of the adoption date. The Company did not elect to apply the hindsight practical expedient when determining lease term and assessing impairment of right-of-use assets. The adoption of ASU 2016-02 resulted in the recognition of right-of-use assets of $618.1 million, current lease liabilities for operating leases of approximately $155.5 million, non-current lease liabilities of $468.4 million and a cumulative-effect adjustment to credit retained earnings of $116.8 million on its Consolidated Balance Sheets, with no material impact to its Consolidated Statements of Operations. See Note P for further information regarding the impact of the adoption of ASU 2016-02 on the Company’s financial statements.

Compensation – Stock Compensation. In June 2018, the FASB issued an ASU 2018-07 which supersedes existing guidance for equity-based payments to nonemployees and expands the scope of guidance for stock compensation to include all share-based payment arrangements related to the acquisition of goods and services from both nonemployees and employees. As a result, the same guidance that provides for employee share-based payments, including most of its requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. The Company adopted this guidance during the first quarter of 2019 and it did not have material impact on its consolidated financial statements.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – New Accounting Principles and Recent Accounting Pronouncements (Contd.)

Recent Accounting Pronouncements

Financial Instruments – Credit Losses. In June 2016, the FASB issued ASU 2016-13 which replaces the impairment model for most financial assets, including trade receivables, from the incurred loss methodology to a forward-looking expected loss model that will result in earlier recognition of credit losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. The Company is currently assessing the potential impact of this ASU, but does not expect a material impact to its consolidated financial statements.

Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13 which modifies disclosure requirements related to fair value measurement. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Implementation on a prospective or retrospective basis varies by specific disclosure requirement. Early adoption is permitted. The standard also allows for early adoption of any removed or modified disclosures upon issuance of this ASU while delaying adoption of the additional disclosures until their effective date. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.

Compensation-Retirement Benefits-Defined Benefit Plans-General. In August 2018, the FASB issued ASU 2018-14 which modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For public companies, the amendments in this ASU are effective for fiscal years beginning after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.

Note C – Revenue from Contracts with Customers

Nature of Goods and Services

The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and gas) in select basins around the globe. The Company’s revenue from sales of oil and gas production activities are primarily subdivided into two key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.

For operated oil and gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production.

U.S.- In the United States, the Company primarily produces oil and gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and gas are transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials.

Canada- In Canada, contracts are primarily long-term floating commodity index priced, except for certain natural gas physical forward sales fixed-price contracts. For the Offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer.

In the third quarter of 2019, the Company made an immaterial reclassification to correct its financial statements to report transportation, gathering, and processing costs as a separate line item (previously reported net in revenue) in the Consolidated Statements of Operations and revised all historical periods to reflect this presentation. There was no resultant change in net income attributable to Murphy.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Revenue from Contracts with Customers (Contd.)

Disaggregation of Revenue

The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.

For the three-months ended September 30, 2019 and 2018, the Company recognized $750.3 million and $475.5 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. For the nine-months ended September 30, 2019 and 2018 the Company recognized $2,060.1 million and $1,330.4 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.



		Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of dollars)		2019		2018		2019	2018
Net crude oil and condensate revenue
United States	Onshore	$	219,515	227,022		547,756	612,194
	Offshore	398,518		95,059		1,090,462	264,174
Canada	Onshore	31,758		34,504		88,730	87,018
	Offshore	28,408		35,929		115,686	141,313
Other		1,933		3,156		7,908	3,156
Total crude oil and condensate revenue		680,132		395,670		1,850,542	1,107,855

Net natural gas liquids revenue
United States	Onshore	5,557		19,196		22,497	48,615
	Offshore	8,414		3,600		18,184	9,013
Canada	Onshore	2,751		4,140		8,987	11,062
Total natural gas liquids revenue		16,722		26,936		49,668	68,690

Net natural gas revenue
United States	Onshore	5,848		8,833		20,762	25,670
	Offshore	15,879		3,965		29,575	11,161
Canada	Onshore	31,756		40,054		109,580	117,023
Total natural gas revenue		53,483		52,852		159,917	153,854
Total revenue from contracts with customers		750,337		475,458		2,060,127	1,330,399

Gain (loss) on crude contracts		63,247		(2,223	)	121,163	(69,349	)
Gain on sale of assets and other income¹		3,493		17,276		10,283	26,713
Total revenue		$	817,077	490,511		2,191,573	1,287,763

¹ Gain on sale of Malaysia operations of $960.0 million is reported in discontinued operations. See Note E.

Contract Balances and Asset Recognition

As of September 30, 2019, and December 31, 2018, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $146.4 million and $147.6 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on historical collections and ability of customers to pay, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.

The Company has not entered into any upstream oil and gas sale contracts that have financing components as at September 30, 2019.

The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Revenue from Contracts with Customers (Contd.)

Performance Obligations

The Company recognizes oil and gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.

For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.

The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the company’s long-term strategy.

As of September 30, 2019, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of 12 months or more starting at the inception of the contract:

໿



Current Long-Term Contracts Outstanding at September 30, 2019

Location	Commodity	End Date	Description	Approximate Volumes
U.S.	Oil	Q4 2021	Fixed quantity delivery in Eagle Ford	17,000 BOED
U.S.	Oil, Gas and NGL	Q2 2026	Deliveries from dedicated acreage in Eagle Ford	As produced
U.S.	NGL	Q4 2020	Dedicated acreage delivery in GOM	As produced
Canada	Gas	Q4 2020	Contracts to sell natural gas at Alberta AECO fixed prices	59 MMCFD
Canada	Gas	Q4 2020	Contracts to sell natural gas at USD Index pricing	60 MMCFD
Canada	Gas	Q4 2021	Contracts to sell natural gas at USD Index pricing	10 MMCFD
Canada	Gas	Q4 2024	Contracts to sell natural gas at USD Index pricing	30 MMCFD
Canada	Gas	Q4 2026	Contracts to sell natural gas at USD Index pricing	38 MMCFD
Canada	Gas	Q4 2026	Contracts to sell natural gas at USD Index pricing	11 MMCFD

Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Property, Plant and Equipment

Exploratory Wells

Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

At September 30, 2019, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $280.7 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2019 and 2018.



(Thousands of dollars)	2019			2018
Beginning balance at January 1	$	207,855		155,103
Additions pending the determination of proved reserves	86,025			41,560
Reclassifications to proved properties based on the determination of proved reserves	—			(2,214	)
Capitalized exploratory well costs charged to expense	(13,145		)	(4,521	)
Balance at September 30	$	280,735		189,928

The capitalized well costs charged to expense during 2019 included the CM-1X and the CT-1X wells in Vietnam Block 11-2/11. The wells were originally drilled in 2017. The capitalized well costs charged to expense in 2018 included the Julong East well in Block CA-1, offshore Brunei in which further development of the well was not sanctioned by the operator and the contract term for development sanctions expired. This well was originally drilled in 2012.

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized. The projects are aged based on the last well drilled in the project.



	September 30,
	2019				2018

(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount		No. of Wells	No. of Projects
Aging of capitalized well costs:
Zero to one year	$	64,711	5	5	$	46,813	1	1
One to two years	63,615		1	1	41,051		3	2
Two to three years	27,500		1	—	5,208		1	1
Three years or more	124,909		5	—	96,856		4	1
	$	280,735	12	6	$	189,928	9	5

Of the $216.0 million of exploratory well costs capitalized more than one year at September 30, 2019, $57.4 million is in Brunei, $67.5 million is in Vietnam, $63.6 million is in the Gulf of Mexico and $27.5 million is in the U.S. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Divestments

In July 2019, the Company completed a divestiture of its two subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., in a transaction with PTT Exploration and Production Public Company Limited (PTTEP) which was effective January 1, 2019. Total cash consideration received upon closing was $2.0 billion. A gain on sale of $960.0 million was recorded as part of discontinued operations on the Consolidated Statement of Operations during the third quarter 2019. The Company does not anticipate tax liabilities related to the sales proceeds. Murphy is entitled to receive a $100.0 million bonus payment contingent upon certain future exploratory drilling results prior to October 2020.

In 2016, a Canadian subsidiary of the Company completed a divestiture of natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. Total cash consideration received upon closing was $414.1 million. A gain on sale of approximately $187.0 million was deferred, up to December 31, 2018, and prior to 2019 was being recognized straight line over the life of the contract in the Canadian operating segment. The remaining deferred gain of $116.8 million, net of tax, was included as a component of Deferred credits and other liabilities in

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Property, Plant and Equipment (Contd.)

the Company’s Consolidated Balance Sheet as of December 31, 2018. As required by ASC 842, effective January 1, 2019, the previously deferred gain related to the sale and leaseback transaction has been transferred to equity upon adoption, lowering liabilities but increasing retained earnings by approximately $116.8 million, net of tax. The Company amortized approximately $5.7 million of the deferred gain during the first nine months of 2018.

Acquisitions

In 2016, a Canadian subsidiary of Murphy Oil acquired a 70% operated working interest (WI) in Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30% non-operated WI in Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. As part of the transaction, Murphy agreed to pay an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of September 30, 2019, $131.6 million of the carried interest had been paid. The remaining carry is to be paid over a period through 2020.

Note E – Discontinued Operations and Assets Held for Sale

The Company has accounted for its Malaysian exploration and production operations, along with the former U.K., U.S. refining and marketing operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three and nine-month period ended September 30, 2019 and 2018 were as follows:



	Three Months Ended September 30,			Nine Months Ended September 30,
(Thousands of dollars)	2019		2018	2019	2018
Revenues ¹	$	972,737	201,370	1,328,110	640,806
Costs and expenses
Lease operating expenses	6,262		49,390	127,138	152,406
Depreciation, depletion and amortization	—		44,326	33,697	139,566
Other costs and expenses (benefits)	11,078		36,642	81,560	55,665
Income before taxes	955,397		71,012	1,085,715	293,169
Income tax expense	2,029		33,200	58,083	106,981
Income from discontinued operations	$	953,368	37,812	1,027,632	186,188

¹ In 2019, includes $960.0 million gain on sale of Malaysia operations.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Discontinued Operations and Assets Held for Sale (Contd.)

The following table presents the carrying value of the major categories of assets and liabilities of the Brunei exploration and production and the U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheet at September 30, 2019. As of December 31, 2018, the Malaysian exploration and production business was also held for sale. The closing of this sale occurred on July 10, 2019.



(Thousands of dollars)	September 30, 2019		December 31, 2018
Current assets
Cash	$	25,307	44,669
Accounts receivable	3,859		103,158
Inventories	406		7,887
Prepaid expenses and other	1,847		18,151
Property, Plant, and Equipment, net	87,556		—
Deferred income taxes and other assets	9,440		—
Total current assets associated with assets held for sale	128,415		173,865
Non-current assets
Property, Plant, and Equipment, net	—		1,325,431
Deferred income taxes and other assets	—		219,577
Total non-current assets associated with assets held for sale	$	—	1,545,008
Current liabilities
Accounts payable	$	8,563	203,236
Other accrued liabilities	448		55,273
Current maturities of long-term debt (finance lease)	696		9,915
Taxes payable	752		18,034
Long-term debt (finance lease)	7,420		—
Asset retirement obligation	235		—
Total current liabilities associated with assets held for sale	18,114		286,458
Non-current liabilities
Long-term debt	—		117,816
Asset retirement obligation	—		274,904
Total non-current liabilities associated with assets held for sale	$	—	392,720

Note F – Financing Arrangements and Debt

On May 30, 2019, the Company entered into a $500 million term loan credit facility (the New Term Credit Facility). The New Term Credit Facility was a senior unsecured guaranteed facility with an original maturity date of December 2, 2019. The covenants within the New Term Credit Facility were substantially consistent with those in the Company’s revolving credit facility (see 2018 facility below), and borrowings under the New Term Credit Facility bore interest at comparable rates to those incurred under the 2018 facility. The New Term Credit Facility was prepayable at any time by the Company and had to be repaid no later than 30 days after closing of the Company’s previously announced Malaysia divestiture. In July 2019, the Company closed the previously announced Malaysia divestiture, repaid and terminated the New Term Credit Facility.

As of September 30, 2019, the Company has a $1.6 billion revolving credit facility (2018 facility). The 2018 facility is a senior unsecured guaranteed facility which expires in November 2023. At September 30, 2019, the Company had no outstanding borrowings under the 2018 facility and $4.6 million of outstanding letters of credit, which reduce the borrowing capacity of the 2018 facility. At September 30, 2019, the interest rate in effect on borrowings under the facility would have been 3.51%. At September 30, 2019, the Company was in compliance with all covenants related to the 2018 facility.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note G – Other Financial Information

Additional disclosures regarding cash flow activities are provided below.໿



	Nine Months Ended September 30,
(Thousands of dollars)	2019			2018
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable ²	$	(128,698	)	(32,372	)
(Increase) decrease in inventories	4,398			21,367
(Increase) decrease in prepaid expenses	(3,745		)	(3	)
Increase (decrease) in accounts payable and accrued liabilities ²	165,224			1,185
Increase (decrease) in income taxes payable	3,078			322
Net (increase) decrease in noncash operating working capital	$	40,257		(9,501	)
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	(4,563	)	(4,508	)
Interest paid, net of amounts capitalized of $0.2 million in 2019 and $0 in 2018	137,116			113,820

Non-cash investing activities:
Asset retirement costs capitalized ¹	$	48,203		2,907
(Increase) decrease in capital expenditure accrual	(52,659		)	27,551

¹ Includes asset retirement obligations assumed as part of the LLOG acquisition of $37.3 million. See Note Q.

²Excludes receivable/payable balances relating to mark-to-market of crude contracts and contingent consideration relating to acquisitions.

Note H – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plan and the U.S. director’s plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three and nine-month periods ended September 30, 2019 and 2018.



	Three Months Ended September 30,
	Pension Benefits					Other Postretirement Benefits
(Thousands of dollars)	2019			2018		2019		2018
Service cost	$	2,064		2,252		421		492
Interest cost	7,151			6,716		945		874
Expected return on plan assets	(6,455		)	(7,476	)	—		—
Amortization of prior service cost (credit)	248			254		(98	)	(10	)
Recognized actuarial loss	3,516			5,197		—		—
Net periodic benefit expense	$	6,524		6,943		1,268		1,356

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Employee and Retiree Benefit Plans (Contd.)



	Nine Months Ended September 30,
	Pension Benefits					Other Postretirement Benefits
(Thousands of dollars)	2019			2018		2019		2018
Service cost	$	6,188		6,761		1,261		1,479
Interest cost	21,402			20,160		2,833		2,622
Expected return on plan assets	(19,285		)	(22,435	)	—		—
Amortization of prior service cost (credit)	741			767		(293	)	(29	)
Recognized actuarial loss	10,538			15,593		—		—
Net periodic benefit expense	$	19,584		20,846		3,801		4,072

The components of net periodic benefit expense, other than the service cost component, are included in the line item “Interest and other income (loss)” in Consolidated Statements of Operations.

During the nine-month period ended September 30, 2019, the Company made contributions of $24.1 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2019 for the Company’s defined benefit pension and postretirement plans is anticipated to be $8.3 million.

Note I – Incentive Plans

The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.

The 2017 Annual Incentive Plan (2017 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the 2017 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.

The 2018 Long-Term Incentive Plan (2018 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2018 Long-Term Plan expires in 2028. A total of 6,750,000 shares are issuable during the life of the 2018 Long-Term Plan, with annual grants limited to one percent (1%) of Common shares outstanding. Shares issued pursuant to awards granted under this Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under this Plan.

The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.

In the first quarter of 2019, the Committee granted 957,600 performance-based RSUs and 327,900 time-based RSUs to certain employees. The fair value of the performance-based RSUs, using a Monte Carlo valuation model, was $28.09 per unit. The fair value of the time-based RSUs was estimated based on the fair market value of the Company’s stock on the date of grant of $28.16 per unit. Additionally, in February 2019, the Committee granted 1,025,900 cash-settled RSUs (CRSU) to certain employees. The CRSUs are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards. The initial fair value of the CRSUs granted in February 2019 was $28.16. Also in February, the Committee granted 78,716 shares of time-based RSUs to the Company’s non-employee Directors under the 2018 Stock Plan for Non-Employee Directors. These units are scheduled to vest on the third anniversary of the date of grant. The estimated fair value of these awards was $27.95 per unit on date of grant.

All stock option exercises are non-cash transactions for the Company. The employee receives net shares, after applicable withholding taxes, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the nine-month period ended September 30, 2019.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Incentive Plans (Contd.)

Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:

Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).

Note J – Earnings per Share

Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three and nine-month periods ended September 30, 2019 and 2018. The following table reports the weighted-average shares outstanding used for these computations.



	Three Months Ended September 30,		Nine Months Ended September 30,
(Weighted-average shares)	2019	2018	2019	2018
Basic method	160,365,705	173,047,246	167,310,202	172,949,450
Dilutive stock options and restricted stock units	614,333	1,128,021	795,025	1,252,310
Diluted method	160,980,038	174,175,267	168,105,227	174,201,760

The following table reflects certain options to purchase shares of common stock that were outstanding during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Antidilutive stock options excluded from diluted shares	2,903,768		2,870,549		3,016,361		3,544,087
Weighted average price of these options	$	44.65	$	54.06	$	45.38	$	50.49

Note K – Income Taxes

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income from continuing operations before income taxes. For the three and nine-month periods ended September 30, 2019 and 2018, the Company’s effective income tax rates were as follows:



	2019	2018
Three months ended September 30,	10.6%	24.1%
Nine months ended September 30,	12.1%	(300.5)%

The effective tax rate for the three-month period ended September 30, 2019 was below the U.S. statutory tax rate of 21% due to an income tax deduction for prior years Vietnam exploration spend which resulted in an income tax benefit of $15.0 million.

The effective tax rate for the three-month period ended September 30, 2018 was above the statutory tax rate primarily due to net losses and exploration expenses in certain foreign jurisdictions for which no income tax benefits will be realized, and income generated in foreign jurisdictions which have income tax rates higher than the U.S. statutory tax rate.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K– Income Taxes (Contd.)

The effective tax rate for the nine-month period ended September 30, 2019 was below the U.S. statutory tax rate of 21% due to to an income tax deduction for prior years Vietnam exploration spend which resulted in an income tax benefit of $15.0 million, a reduction of the Alberta provincial corporate income tax rate that reduced the future deferred tax liability by $13.0 million, and no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

For the nine-month period ended September 30, 2018 the effective tax rate is lower than the statutory tax rate of 21% because the Company reported a favorable tax adjustment related to the 2017 Tax Act. The IRS’s April 2, 2018 guidance allowed for the preservation of 2017 operating loss carryforwards under the 2017 Tax Act’s taxation of unrepatriated foreign earnings. The preservation of the tax loss carryforward reduced the deferred tax expense by $156 million and resulted in a $36 million charge to taxes payable for a net $120 million tax benefit.

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take multiple years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of September 30, 2019, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2016; Canada – 2015; Malaysia – 2012; and United Kingdom – 2017. Following the divestment of Malaysia, the Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. The Company believes current recorded liabilities are adequate.

Note L – Financial Instruments and Risk Management

Murphy uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes and it does not use derivatives with leveraged or complex features. Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations. Certain interest rate derivative contracts were accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in Accumulated other comprehensive loss until the anticipated transactions occur.

Commodity Price Risks

At September 30, 2019, the Company had 35,000 barrels per day in WTI crude oil swap financial contracts maturing through the end of 2019 at an average price of $60.51 and 35,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2020 at an average price of $57.59. Under these contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price.

At September 30, 2018, the Company had 21,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2018 at an average price of $54.88.

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange short-term derivatives outstanding at September 30, 2019 and 2018.

At September 30, 2019 and December 31, 2018, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

September 30, 2019

December 31, 2018

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts receivable

104,358

Accounts receivable

3,837

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Financial Instruments and Risk Management (Contd.)

For the three-month and nine-month periods ended September 30, 2019 and September 30, 2018, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.



		Gain (Loss)				Gain (Loss)
(Thousands of dollars)		Three Months Ended September 30,				Nine months ended September 30,
Type of Derivative Contract	Statement of Operations Location	2019		2018		2019	2018
Commodity	Gain (loss) on crude contracts	$	63,247	(2,223	)	121,163	(69,349	)

Interest Rate Risks

Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10 years notes sold in May 2012 to match the payment of interest on these notes through 2022. During each of the nine-month periods ended September 30, 2019 and 2018, $2.2 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations. The remaining loss (net of tax) deferred on these matured contracts at September 30, 2019 was $6.1 million, which is recorded, net of income taxes of $1.6 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately $0.7 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remainder of 2019.

Fair Values – Recurring

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, 2019 and December 31, 2018, are presented in the following table.



	September 30, 2019					December 31, 2018
(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Assets:
Commodity derivative contracts	$	—	104,358	—	104,358	—	3,837	—	3,837
	$	—	104,358	—	104,358	—	3,837	—	3,837

Liabilities:
Nonqualified employee savings plans	$	15,499	—	—	15,499	13,845	—	—	13,845
Contingent consideration	—		—	137,688	137,688	—	—	47,730	47,730
	$	15,499	—	137,688	153,187	13,845	—	47,730	61,575

The fair value of WTI crude oil derivative contracts in 2018 and 2019 were based on active market quotes for WTI crude oil. The income effect of changes in the fair value of crude oil derivative contracts is recorded in Gain (loss) on crude contracts in the Consolidated Statements of Operations.

The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and general expenses in the Consolidated Statements of Operations.

The contingent consideration, related to two acquisitions in 2018 and 2019, is valued using a Monte Carlo simulation model. The income effect of changes in the fair value of the contingent consideration is recorded in Other (income) expense in the Consolidated Statements of Operations.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Financial Instruments and Risk Management (Contd.)

The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at September 30, 2019 and December 31, 2018. Subsequent to the balance sheet date, the Company has entered into additional derivative instruments to manage certain risks related to commodity prices, bringing the total outstanding as of October 30, 2019 to 45,000 barrels per day in WTI crude oil swap financial contracts for 2020, at an average price of $56.42 per barrel.

Note M – Accumulated Other Comprehensive Loss

The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2018 and September 30, 2019 and the changes during the nine-month period ended September 30, 2019, are presented net of taxes in the following table.



(Thousands of dollars)	Foreign Currency Translation Gains (Losses)			Retirement and Postretirement Benefit Plan Adjustments			Deferred Loss on Interest Rate Derivative Hedges			Total
Balance at December 31, 2018	$	(419,852	)	(182,036	)		(7,899	)		(609,787	)
2019 components of other comprehensive income (loss):
Before reclassifications to income and retained earnings	36,927			—			—			36,927
Reclassifications to income	—			8,277		¹	1,756		²	10,033
Net other comprehensive income (loss)	36,927			8,277			1,756			46,960
Balance at September 30, 2019	$	(382,925	)	(173,759	)		(6,143	)		(562,827	)

¹Reclassifications before taxes of $10,598 are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2019. See Note H for additional information. Related income taxes of $2,321 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2019.

²Reclassifications before taxes of $2,223 are included in Interest expense, net, for the nine-month period ended September 30, 2019. Related income taxes of $467 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2019. See Note L for additional information.

Note N – Environmental and Other Contingencies

The Company’s operations and earnings have been, and may be, affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes and retroactive tax claims; royalty and revenue sharing changes; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences or may be taken in response to actions of other governments. It is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note N– Environmental and Other Contingencies (Contd.)

Murphy’s control. Under existing laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup and the Company is investigating the extent of any such liability and the availability of applicable defenses.

The Company has retained certain liabilities related to environmental and operational matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. The Company has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred, at known or currently unidentified sites, is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

Note O – Business Segments

Information about business segments and geographic operations is reported in the following table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, other gains and losses (including foreign exchange gains/losses and realized and unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals.໿



(Millions of dollars)	Total Assets at September 30, 2019		Three Months Ended September 30, 2019			Three Months Ended September 30, 2018
(Millions of dollars)	Total Assets at September 30, 2019		External Revenues	Income (Loss)		External Revenues		Income (Loss)
Exploration and production ¹
United States	$	8,149.5	656.8	170.8		357.8		91.6
Canada	2,212.5		95.0	(9.1	)	114.9		12.5
Other	253.3		1.9	(3.7	)	19.9		1.3
Total exploration and production	10,615.3		753.7	158.0		492.6		105.4
Corporate	1,151.2		63.4	0.3		(2.1	)	(49.3	)
Assets/revenue/income from continuing operations	11,766.5		817.1	158.3		490.5		56.1
Discontinued operations, net of tax	17.2		—	953.4		—		37.8
Total	$	11,783.7	817.1	1,111.7		490.5		93.9

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note O – Business Segments (Contd.)



(Millions of dollars)	Nine Months Ended September 30, 2019				Nine Months Ended September 30, 2018
(Millions of dollars)	External Revenues		Income (Loss)		External Revenues		Income (Loss)
Exploration and production ¹
United States	$	1,734.3	420.0		971.7		200.3
Canada	323.8		(7.5	)	357.6		46.7
Other	7.9		(35.4	)	19.9		(28.8	)
Total exploration and production	2,066.0		377.1		1,349.2		218.2
Corporate	125.6		(97.0	)	(61.4	)	(96.7	)
Assets/revenue/income from continuing operations	2,191.6		280.1		1,287.8		121.5
Discontinued operations, net of tax	—		1,027.6		—		186.2
Total	$	2,191.6	1,307.7		1,287.8		307.7

¹ Additional details about results of oil and gas operations are presented in the tables on pages 31 and 32.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Leases

Significant Accounting Policy

At inception, contracts are assessed for the presence of a lease according to criteria laid out by ASC 842. If a lease is present, further criteria is assessed to determine if the lease should be classified as an operating or finance lease. Operating leases are presented on the Consolidated Balance Sheet as Operating lease assets with the corresponding lease liabilities presented in Operating lease liabilities and Non-current operating lease liabilities. Finance lease assets are presented on the Consolidated Balance Sheet within Assets held for sale with the corresponding liabilities presented in Current maturities of long-term debt and Long-term debt. See Note E – Discontinued Operations for amounts in Assets held for sale.

Generally, lease liabilities are recognized at commencement and based on the present value of the future minimum lease payments to be made over the lease term. Lease assets are then recognized based on the value of the lease liabilities. Where implicit lease rates are not determinable, the minimum lease payments are discounted using the Company’s collateralized incremental borrowing rates.

Operating leases are expensed according to their nature and recognized in Lease operating expenses, Selling and general expenses or capitalized in the Consolidated Financial Statements. Finance leases are depreciated with expenses recognized in Depreciation, depletion, and amortization and Interest expense, net on the Consolidated Statement of Operations.

Nature of Leases

The Company has entered into various operating leases such as a gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and gas field equipment. Remaining lease terms range from 1 year to 17 years, some of which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month. Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of both at Company discretion and mutual agreement between the Company and lessor. Purchase options also exist for certain leases.

Related Expenses

Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows:



(Thousands of dollars)	Financial Statement Category	Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
Operating lease ^1,2	Lease operating expenses	$	62,260		178,164
Operating lease ²	Selling and general expense	2,700			9,044
Operating lease ²	Other operating expense	1,011			1,905
Operating lease ²	Property, plant and equipment	53,117			108,679
Operating lease ²	Asset retirement obligations	—			3,024
Finance lease
Amortization of asset	Depreciation, depletion and amortization	—			420
Interest on lease liabilities	Interest expense, net	—			202
Sublease income	Other income	(395		)	(1,034	)
Net lease expense		$	118,693		300,404

¹ For the three months and nine months ended September 30, 2019, includes variable lease expenses of $9.0 million and $22.8 million, respectively, primarily related to additional volumes processed at a gas processing plant.

² The three months ended September 30, 2019 includes $10.9 million for Lease operating expense, $1.0 million for Selling and general expense, $37.4 million for Property, plant and equipment, net relating to short-term leases due within 12 months. For the nine months ended includes $33.3 million for Lease operating expense, $3.1 million for Selling and general expense, $86.2 million for Property, plant and equipment, net and $3.0 million for Asset retirement obligations relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and gas field equipment.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Leases (Contd.)

Maturity of Lease Liabilities໿



(Thousands of dollars)	Operating Leases ¹			Finance Leases		Total
2019	$	53,597		267		53,864
2020	136,283			1,069		137,352
2021	57,190			1,069		58,259
2022	54,955			1,069		56,024
2023	54,453			1,069		55,522
Remaining	471,202			5,610		476,812
Total future minimum lease payments	827,680			10,153		837,833
Less imputed interest	(253,403		)	(1,985	)	(255,388	)
Present value of lease liabilities²	$	574,277		8,168		582,445

¹ Excludes $272.6 million of minimum lease payments for leases entered but not yet commenced. These payments relate to an expansion of an existing gas processing plant and payments are anticipated to commence at the end of 2020 for 20 years.

² Includes both the current and long-term portion of the lease liabilities.

Lease Term and Discount Rate



	September 30, 2019
Weighted average remaining lease term:
Operating leases	11 years
Finance leases	10 years
Weighted average discount rate:
Operating leases	4.8	%
Finance leases	4.7	%

Other Information໿



(Thousands of dollars)	Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	140,424
Operating cash flows from finance leases	306
Financing cash flows from finance leases	510
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	$	31,281

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note Q – Acquisitions

PAI Acquisition:

In December 2018, the Company announced the completion of a transaction with Petrobras Americas Inc. (PAI) which was effective October 1, 2018. Through this transaction, Murphy acquired all PAI’s producing Gulf of Mexico assets along with certain blocks that hold deep exploration rights. This transaction added approximately 97 MMBOE (including noncontrolling interest, NCI) of proven reserves at December 31, 2018.

Under the terms of the transaction, Murphy paid cash consideration of $775.4 million and transferred a 20% interest in MP Gulf of Mexico, LLC (MP GOM), a subsidiary of Murphy, to PAI. Murphy also has an obligation to pay additional contingent consideration up to $150 million if certain sales thresholds are exceeded beginning in 2019 through 2025. Both companies contributed all of their current producing Gulf of Mexico assets into MP GOM. MP GOM is owned 80% by Murphy and 20% by PAI, with Murphy overseeing the operations.

LLOG Acquisition:

In June 2019, the Company announced the completion of a transaction with LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) which was effective January 1, 2019. Through this transaction, Murphy acquired strategic deepwater Gulf of Mexico assets which added approximately 67 MMBOE of proven reserves at May 31, 2019.

Under the terms of the transaction, Murphy paid cash consideration of $1,226.3 million and has an obligation to pay additional contingent consideration of up to $200 million in the event that certain revenue thresholds are exceeded between 2019 and 2022; and $50 million following first oil from certain development projects.

The following table contains the preliminary purchase price allocations at fair value:



(Thousands of dollars)	PAI			LLOG
Cash consideration paid	$	775,413		1,226,261
Fair value of net assets contributed	154,469			—
Contingent consideration	52,540			89,444
NCI in acquired assets	245,605			—
Total purchase consideration	$	1,228,027		1,315,705
(Thousands of dollars)
Fair value of Property, plant and equipment	$	1,610,790		1,340,206
Other assets	5,628			12,771
Less: Asset retirement obligations	(388,391		)	(37,272	)
Total net assets	$	1,228,027		1,315,705

The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average discount rate. These inputs require significant judgments and estimates by management at the time of the valuation, are sensitive, and may be subject to change.

Certain data necessary to complete the purchase price allocations are not yet available, and includes, but is not limited to, analysis of the underlying tax basis of the acquired assets and assumed liabilities as well as the final purchase price adjustments to be settled in 2019. We expect to complete the purchase price allocations during the 12-month periods following the acquisition dates of November 30, 2018 and May 31, 2019, during which time the value of the assets and liabilities may be revised as appropriate.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note Q– Acquisitions (Contd.)

Results of Operations

Murphy’s Consolidated Statement of Operations for the three months ended September 30, 2019, included additional revenues of $263.7 million and pre-tax income of $99.6 million attributable to the acquired PAI assets. For the nine months ended September 30, 2019, additional revenues of $710.2 million and pre-tax income of $369.7 million attributable to the acquired PAI assets were included in the Consolidated Statement of Operations.

Murphy’s Consolidated Statement of Operations for the three month period ended September 30, 2019, included additional revenues of $126.4 million and pre-tax income of $29.2 million attributable to the acquired LLOG assets. For the nine months ended September 30, 2019, additional revenues of $159.8 million and pre-tax income of $34.3 million attributable to the acquired LLOG assets.

Pro Forma Financial Information

The following pro forma condensed combined financial information was derived from historical financial statements of Murphy, PAI and LLOG and gives effect to the transaction as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable. The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the transaction or any estimated costs that have been, or will be, incurred by us to integrate the PAI assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2018; furthermore, the financial information is not intended to be a projection of future results.



(Thousands of dollars, except per share amounts)	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Revenues	$	855,689	2,383,296
Net Income Attributable to Murphy	266,275		823,704

Net Income Attributable to Murphy per Common Share
Basic	$	1.54	4.76
Diluted	1.53		4.73

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

Overall Review

On July 10, 2019, the Company announced that a subsidiary closed the sale to divest the issued share capital of the entities primarily conducting Murphy’s operations in Malaysia to a subsidiary of PTT Exploration and Production Public Company Limited (PTTEP). After closing adjustments, Murphy received proceeds of approximately $2,035 million and recorded a gain on sale of $960.0 million. As of December 31, 2018, the assets and liabilities of the Malaysia business have been classified as held for sale. In the Statements of operations, the Malaysia results of operations have been reported as discontinued operations for all periods presented.

During the third quarter of 2019, the Company completed $105.9 million in share repurchases. Murphy purchased 5.0 million shares outstanding at an average price of $21.10 per share. During the nine months ended September 30, 2019, the Company repurchased 16.4 million shares outstanding for $405.6 million. Subsequent to quarter end, the Company repurchased 4.3 million shares outstanding for $93.9 million, marking the completion of the $500 million share repurchase program.

For the three months ended September 30, 2019, the Company produced 203 thousand barrels of oil equivalent per day (including noncontrolling interest and excluding Malaysia) from continuing operations. The Company invested $356.6 million in capital expenditures, on a value of work done basis, in the third quarter of 2019. The Company reported net income from continuing operations (which includes income attributable to noncontrolling interest of $22.7 million) of $158.3 million for the three months ended September 30, 2019.

For the nine months ended September 30, 2019, the Company produced 179 thousand barrels of oil equivalent per day (including noncontrolling interest and excluding Malaysia) from continuing operations. The Company invested $2,329.1 million in capital expenditures, on a value of work done basis, in the nine months ended September 30, 2019, which included the LLOG acquisition of $1,226.3 million. The Company reported net income from continuing operations (which includes income attributable to noncontrolling interest of $86.3 million) of $280.1 million for the nine months ended September 30, 2019.

During the three-month and nine-month periods ended September 30, 2019, crude oil and condensate volumes from continuing operations were higher than the prior periods as a result of two Gulf of Mexico acquisitions. The additional income from higher volumes was partially offset by lower benchmark oil prices that were below average comparable benchmark prices during 2018. The results are explained in more detail below.

Results of Operations

Murphy’s income (loss) by type of business is presented below.໿



	Income (Loss)
	Three Months Ended September 30,				Nine Months Ended September 30,
(Millions of dollars)	2019		2018		2019		2018
Exploration and production	$	158.0	105.4		377.1		218.2
Corporate and other	0.3		(49.3	)	(97.0	)	(96.7	)
Income from continuing operations	158.3		56.1		280.1		121.5
Discontinued operations	953.4		37.8		1,027.6		186.2
Net income including noncontrolling interest	$	1,111.7	93.9		1,307.7		307.7

Exploration and Production

Results of E&P continuing operations are presented by geographic segment below.



	Income (Loss)
	Three Months Ended September 30,				Nine Months Ended September 30,
(Millions of dollars)	2019			2018	2019		2018
Exploration and production
United States	$	170.8		91.6	420.0		200.3
Canada	(9.1		)	12.5	(7.5	)	46.7
Other International	(3.7		)	1.3	(35.4	)	(28.8	)
Total	$	158.0		105.4	377.1		218.2

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

Third quarter 2019 vs. 2018

United States E&P operations reported earnings of $170.8 million in the third quarter of 2019 compared to income of $91.6 million in the third quarter of 2018. Results were $79.2 million favorable in the 2019 quarter compared to the 2018 period due to higher revenues ($299.0 million) and lower other operating expense ($25.5 million), partially offset by higher depreciation, depletion and amortization ($120.9 million), lease operating expenses ($64.2 million), transportation, gathering, and processing expenses ($35.0 million), income tax expense ($16.4 million), and G&A ($8.7 million). Higher revenues were primarily due to higher volumes in the U.S. Gulf of Mexico (as a result of the MP GOM transaction in the fourth quarter of 2018 and the LLOG acquisition in the second quarter of 2019). Lower other operating expense was due to gains on the fair market revaluation of acquisition contingent consideration. Higher lease operating expenses and depreciation expense was primarily due to higher volumes. Higher exploration charges were due to higher geological and geophysical expense principally in the Gulf of Mexico.

Canadian E&P operations reported a loss of $9.1 million in the third quarter 2019 compared to income of $12.5 million in the 2018 quarter. Results were unfavorable $21.6 million compared to the 2018 period primarily due to lower revenue ($19.9 million) and higher depreciations and amortization ($6.7 million). Lower revenue was principally due to lower commodity prices and lower volumes at Hibernia (due to a 68 day shut-in), partially offset by higher volumes at Kaybob and Tupper. Higher depreciation was a result of higher volumes sold at Kaybob.

Other international E&P operations reported a loss from continuing operations of $3.7 million in the third quarter of 2019 compared to a net income of $1.3 million in the prior year quarter. The result was $5.0 million unfavorable in the 2019 period versus 2018 primarily due to no repeat of the prior year recording of net revenue and costs ($16.0 million) relating to the working interest in Block CA1 in Brunei, partially offset by lower exploration expenses ($6.5 million) and an income tax benefit in the quarter ($6.3 million).

Nine months 2019 vs. 2018

United States E&P operations reported earnings of $420.0 million in the first nine months of 2019 compared to income of $200.3 million in the first nine months of 2018. Results were $219.7 million favorable in the 2019 quarter compared to the 2018 period due to higher revenues ($762.6 million), partially offset by higher depreciation, depletion and amortization ($236.2 million), lease operating expenses ($145.7 million), transportation, gathering, and processing ($77.3 million), income tax expense ($37.5 million), other operating expense ($25.1 million) and general and administrative (G&A: $13.9 million). Higher revenues were primarily due to higher volumes in the U.S. Gulf of Mexico (as a result of the MP GOM transaction in the fourth quarter of 2018 and the LLOG acquisition in the second quarter of 2019). Higher lease operating expenses and depreciation expense were due primarily to higher volumes. Higher other operating expense was due to higher business development spend relating to acquisition transaction costs. Higher G&A is due to higher long-term incentive charges.

Canadian E&P operations reported a loss of $7.5 million in the first nine months of 2019 compared to income of $46.7 million in the first nine months of 2018. Results were unfavorable $54.2 million compared to the 2018 period primarily due to lower revenue ($33.7 million), higher lease operating expense ($16.1 million), lower other income ($14.0 million) primarily related to more Seal insurance proceeds received in 2018; and partially offset by lower income tax charges ($21.6 million). Lower revenues were due to lower oil and condensate prices than the prior year and a 68 day shut-in at Hibernia in the third quarter, partially offset by higher volumes at Kaybob and Tupper. Higher lease operating expenses were due to higher costs at Tupper as a result of transferring a gain on a previous sale and lease-back transaction to equity as a result of the implementation of ASC 842 (see Note D). In 2018, this gain was being credited to operating expenses equally over the life of the lease.

Other international E&P operations reported a loss from continuing operations of $35.4 million in the first nine months of 2019 compared to a net loss of $28.8 million in the prior year. The 2019 result of $35.4 million loss included the write-off of previously suspended exploration costs of $13.2 million attributable to the CM-1X and the CT-1X wells (originally drilled in 2017) in Vietnam and lower revenues from Brunei ($12.0 million), partially offset by higher tax benefits ($13.0 million). Higher tax benefits were due to deductions relating to the prior year exploration spend.

Third quarter 2019 vs. 2018

All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.

Total hydrocarbon production from continuing operations averaged 203,035 barrels of oil equivalent per day in the third quarter of 2019, which represented a 66% increase from the 122,616 barrels per day produced in the 2018 quarter. The increase was principally due to the acquisition of producing Gulf of Mexico assets as part of the MP GOM transaction in the fourth quarter 2018 and the addition of further Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

Average crude oil and condensate production from continuing operations was 122,950 barrels per day in the third quarter of 2019 compared to 60,486 barrels per day in the third quarter of 2018. The increase of 62,464 barrels per day was principally due to higher volumes in the Gulf of Mexico (56,205 barrels per day) due to the acquisition of assets as part of the MP GOM transaction and the LLOG acquisition and higher volumes in Eagleford (6,748 barrels per days). On a worldwide basis, the Company’s crude oil and condensate prices averaged $59.40 per barrel in the third quarter 2019 compared to $71.73 per barrel in the 2018 period, a decrease of 17% quarter to quarter.

Total production of natural gas liquids (NGL) from continuing operations was 13,601 barrels per day in the third quarter 2019 compared to 8,867 barrels per day in the 2018 period. The average sales price for U.S. NGL was $12.47 per barrel in the 2019 quarter compared to $31.89 per barrel in 2018. The average sales price for NGL in Canada was $21.03 per barrel in the 2019 quarter compared to $41.10 per barrel in 2018. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.

Natural gas sales volumes from continuing operations averaged 399 million cubic feet per day (MMCFD) in the third quarter 2019 compared to 320 MMCFD in 2018. The increase of 79 MMCFD was a result of higher volumes in the Gulf of Mexico (58 MMCFD) and higher volumes in Canada (25 MMCFD). Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the MP GOM transaction and the LLOG acquisition. Higher volumes in Canada was a result of more Tupper wells coming online in the 2019 quarter.

Natural gas prices for the total Company averaged $1.46 per thousand cubic feet (MCF) in the 2019 quarter, versus $1.80 per MCF average in the same quarter of 2018. Average prices in the US and Canada in the quarter were $2.31 and $1.16 respectively.

Nine months 2019 vs. 2018

All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.

Total hydrocarbon production from continuing operations averaged 178,658 barrels of oil equivalent per day in the first nine months of 2019, which represented a 48% increase from the 120,533 barrels per day produced in the first nine months of 2018. The increase is principally due to the acquisition of producing Gulf of Mexico assets as part of the MP GOM transaction in the fourth quarter 2018 and the addition of further Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.

Average crude oil and condensate production from continuing operations was 110,762 barrels per day in the first nine months of 2019 compared to 59,645 barrels per day in the first nine months of 2018. The increase of 51,117 barrels per day was principally due to higher volumes in the Gulf of Mexico (50,185 barrels per day) due to the acquisition of assets as part of the MP GOM transaction and the LLOG acquisition On a worldwide basis, the Company’s crude oil and condensate prices averaged $60.84 per barrel in the first nine months of 2019 compared to $68.55 per barrel in the 2018 period, a decrease of 11% year over year.

Total production of natural gas liquids (NGL) from continuing operations was 10,990 barrels per day in the first nine months of 2019 compared to 8,852 barrels per day in the 2018 period. The average sales price for U.S. NGL was $15.22 per barrel in 2019 compared to $26.90 per barrel in 2018. The average sales price for NGL in Canada was $27.50 per barrel in 2019 compared to $40.32 per barrel in 2018. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.

Natural gas sales volumes from continuing operations averaged 341 million cubic feet per day (MMCFD) in the first nine months quarter 2019 compared to 312 MMCFD in 2018. The increase of 29 MMCFD was a primarily the result of higher volumes in the Gulf of Mexico (30 MMCFD). Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the MP GOM transaction and the LLOG acquisition.

Natural gas prices for the total Company averaged $1.71 per thousand cubic feet (MCF) in the 2019 quarter, versus $1.81 per MCF average in the same quarter of 2018. Average prices in the US and Canada in the quarter were $2.48 and $1.50 respectively.

Additional details about results of oil and gas operations are presented in the tables on pages 31 and 32.

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

The following table contains hydrocarbons produced during the three and nine-month periods ended September 30, 2019 and 2018.



		Three Months Ended September 30,			Nine Months Ended September 30,
Barrels per day unless otherwise noted		2019		2018	2019		2018
Continuing operations
Net crude oil and condensate
United States	Onshore	40,582		33,909	33,256		32,519
	Gulf of Mexico ¹	70,583		14,378	64,266		14,081
Canada	Onshore	7,101		6,096	6,503		5,242
	Offshore	4,333		5,570	6,302		7,237
Other		351		533	435		566
Total net crude oil and condensate - continuing operations		122,950		60,486	110,762		59,645
Net natural gas liquids
United States	Onshore	5,582		6,687	5,621		6,756
	Gulf of Mexico ¹	6,597		1,085	4,172		1,091
Canada	Onshore	1,422		1,095	1,197		1,005
Total net natural gas liquids - continuing operations		13,601		8,867	10,990		8,852
Net natural gas – thousands of cubic feet per day
United States	Onshore	29,122		33,031	30,203		32,329
	Gulf of Mexico ¹	72,897		14,485	44,029		13,811
Canada	Onshore	296,883		272,061	267,205		266,077
Total net natural gas - continuing operations		398,902		319,577	341,437		312,217
Total net hydrocarbons - continuing operations including NCI ^2,3		203,035		122,616	178,658		120,533
Noncontrolling interest
Net crude oil and condensate – barrels per day		(10,322	)	—	(11,215	)	—
Net natural gas liquids – barrels per day		(478	)	—	(496	)	—
Net natural gas – thousands of cubic feet per day		(3,403	)	—	(3,933	)	—
Total noncontrolling interest		(11,367	)	—	(12,367	)	—
Total net hydrocarbons - continuing operations excluding NCI ^2,3		191,668		122,616	166,292		120,533
Discontinued operations
Net crude oil and condensate – barrels per day		1,748		27,269	16,331		29,136
Net natural gas liquids – barrels per day		37		689	434		673
Net natural gas – thousands of cubic feet per day ²		9,624		109,213	67,863		112,516
Total discontinued operations		3,389		46,160	28,076		48,562
Total net hydrocarbons produced excluding NCI ^2,3		195,057		168,776	194,367		169,095

¹2019 includes net volumes attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).

²Natural gas converted on an energy equivalent basis of 6:1

³NCI – noncontrolling interest in MP GOM.

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

The following table contains hydrocarbons sold during the three and nine-month periods ended September 30, 2019 and 2018.



		Three Months Ended September 30,			Nine Months Ended September 30,
Barrels per day unless otherwise noted		2019		2018	2019		2018
Continuing operations
Net crude oil and condensate
United States	Onshore	40,582		33,757	33,256		32,347
	Gulf of Mexico ¹	71,380		14,530	64,532		14,253
Canada	Onshore	7,101		6,096	6,503		5,242
	Offshore	4,945		5,116	6,523		7,197
Other		309		461	415		155
Total net crude oil and condensate - continuing operations		124,317		59,960	111,229		59,194
Net natural gas liquids
United States	Onshore	5,582		6,663	5,622		6,735
	Gulf of Mexico ¹	6,597		1,109	4,172		1,112
Canada	Onshore	1,422		1,095	1,197		1,005
Total net natural gas liquids - continuing operations		13,601		8,867	10,991		8,852
Net natural gas – thousands of cubic feet per day
United States	Onshore	29,122		32,718	30,203		32,172
	Gulf of Mexico ¹	72,897		14,798	44,029		13,968
Canada	Onshore	296,882		272,061	267,205		266,077
Total net natural gas - continuing operations		398,901		319,577	341,437		312,217
Total net hydrocarbons - continuing operations including NCI ^2,3		204,402		122,090	179,126		120,082
Noncontrolling interest
Net crude oil and condensate – barrels per day		(10,481	)	—	(11,269	)	—
Net natural gas liquids – barrels per day		(478	)	—	(496	)	—
Net natural gas – thousands of cubic feet per day²		(3,403	)	—	(3,933	)	—
Total noncontrolling interest		(11,526	)	—	(12,421	)	—
Total net hydrocarbons - continuing operations excluding NCI ^2,3		192,875		122,090	166,706		120,082

Discontinued operations
Net crude oil and condensate – barrels per day		1,424		25,638	16,177		28,551
Net natural gas liquids – barrels per day		32		774	395		790
Net natural gas – thousands of cubic feet per day²		9,624		109,213	67,863		112,516
Total discontinued operations		3,060		44,614	27,883		48,094
Total net hydrocarbons sold excluding NCI ^2,3		195,935		166,704	194,588		168,176

¹2019 includes net volumes attributable to a noncontrolling interest in MP GOM.

²Natural gas converted on an energy equivalent basis of 6:1

³NCI – noncontrolling interest in MP GOM.

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

The following table contains the weighted average sales prices excluding transportation cost deduction for the three and nine-month periods ended September 30, 2019 and 2018.໿ Comparative periods are conformed to current presentation.



		Three Months Ended September 30,			Nine Months Ended September 30,
		2019		2018	2019	2018
Weighted average Exploration and Production sales prices
Continuing operations
Crude oil and condensate – dollars per barrel
United States	Onshore	$	58.80	72.82	60.33	68.97
	Gulf of Mexico ¹	60.69		71.86	61.90	68.72
Canada ²	Onshore	48.61		61.53	49.98	60.80
	Offshore	62.44		76.34	64.97	71.92
Other		67.96		74.37	69.86	74.37
Natural gas liquids – dollars per barrel
United States	Onshore	10.82		31.17	14.66	26.29
	Gulf of Mexico ¹	13.86		36.12	15.96	30.26
Canada ²	Onshore	21.03		41.10	27.50	40.32
Natural gas – dollars per thousand cubic feet
United States	Onshore	2.18		2.92	2.51	2.91
	Gulf of Mexico ¹	2.37		2.98	2.46	2.96
Canada ²	Onshore	1.16		1.60	1.50	1.61
Discontinued operations
Crude oil and condensate – dollars per barrel
Malaysia ³	Sarawak	—		63.82	70.39	66.25
	Block K	69.24		68.67	65.75	66.35
Natural gas liquids – dollars per barrel
Malaysia ³	Sarawak	54.11		70.28	48.23	70.91
Natural gas – dollars per thousand cubic feet
Malaysia ³	Sarawak	3.69		3.91	3.60	3.72
	Block K	0.23		0.24	0.24	0.24

¹ Prices include the effect of noncontrolling interest share for MP GOM.

²U.S. dollar equivalent.

³ Prices are net of payments under the terms of the respective production sharing contracts.

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018



(Millions of dollars)	United States ¹			Canada		Other		Total
Three Months Ended September 30, 2019
Oil and gas sales and other operating revenues	$	656.8		95.0		1.9		753.7
Lease operating expenses	116.2			31.2		0.2		147.6
Severance and ad valorem taxes	13.4			0.4		—		13.8
Transportation, gathering and processing	44.1			10.2		—		54.3
Depreciation, depletion and amortization	253.5			65.3		0.6		319.4
Accretion of asset retirement obligations	9.0			1.6		—		10.6
Exploration expenses
Dry holes and previously suspended exploration costs	(0.1		)	—		—		(0.1	)
Geological and geophysical	0.2			—		0.2		0.4
Other exploration	1.5			0.1		3.8		5.4
	1.6			0.1		4.0		5.7
Undeveloped lease amortization	5.2			0.3		1.0		6.5
Total exploration expenses	6.8			0.4		5.0		12.2
Selling and general expenses	22.7			7.6		5.6		35.9
Other	(21.0		)	(7.3	)	0.5		(27.8	)
Results of operations before taxes	212.1			(14.4	)	(10.0	)	187.7
Income tax provisions (benefits)	41.3			(5.3	)	(6.3	)	29.7
Results of operations (excluding corporate overhead and interest)	$	170.8		(9.1	)	(3.7	)	158.0

Three Months Ended September 30, 2018
Oil and gas sales and other operating revenues	$	357.8		114.9		19.9		492.6
Lease operating expenses	52.0			31.5		0.2		83.7
Severance and ad valorem taxes	14.8			0.3		—		15.1
Transportation, gathering and processing	9.1			7.8		—		16.9
Depreciation, depletion and amortization	132.6			58.6		1.0		192.2
Accretion of asset retirement obligations	4.5			1.9		—		6.4
Exploration expenses
Dry holes and previously suspended exploration costs	—			—		4.5		4.5
Geological and geophysical	0.4			—		0.7		1.1
Other exploration	1.6			0.2		5.5		7.3
	2.0			0.2		10.7		12.9
Undeveloped lease amortization	7.8			0.2		0.8		8.8
Total exploration expenses	9.8			0.4		11.5		21.7
Selling and general expenses	14.0			6.4		6.2		26.6
Other	4.5			(9.5	)	0.6		(4.4	)
Results of operations before taxes	116.5			17.5		0.4		134.4
Income tax provisions (benefits)	24.9			5.0		(0.9	)	29.0
Results of operations (excluding corporate overhead and interest)	$	91.6		12.5		1.3		105.4

¹ 2019 includes results attributable to a noncontrolling interest in MP GOM.

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018



(Millions of dollars)	United States ¹			Canada		Other		Total
Nine Months Ended September 30, 2019
Oil and gas sales and other operating revenues	$	1,734.3		323.8		7.9		2,066.0
Lease operating expenses	308.3			107.1		1.1		416.5
Severance and ad valorem taxes	36.0			1.0		—		37.0
Transportation, gathering and processing	103.4			25.3		—		128.7
Depreciation, depletion and amortization	618.6			181.6		2.9		803.1
Accretion of asset retirement obligations	25.2			4.6		—		29.8
Exploration expenses
Dry holes and previously suspended exploration costs	(0.2		)	—		13.1		12.9
Geological and geophysical	16.1			—		8.1		24.2
Other exploration	5.5			0.3		10.9		16.7
	21.4			0.3		32.1		53.8
Undeveloped lease amortization	18.0			1.0		2.7		21.7
Total exploration expenses	39.4			1.3		34.8		75.5
Selling and general expenses	52.9			21.3		17.3		91.5
Other	37.5			(6.9	)	0.9		31.5
Results of operations before taxes	513.0			(11.5	)	(49.1	)	452.4
Income tax provisions (benefits)	93.0			(4.0	)	(13.7	)	75.3
Results of operations (excluding corporate overhead and interest)	$	420.0		(7.5	)	(35.4	)	377.1

Nine months ended September 30, 2018
Oil and gas sales and other operating revenues	$	971.7		357.5		19.9		1,349.1
Lease operating expenses	162.6			91.0		0.2		253.8
Severance and ad valorem taxes	39.2			0.9		—		40.1
Transportation, gathering and processing	26.1			23.7		—		49.8
Depreciation, depletion and amortization	382.4			171.1		2.4		555.9
Accretion of asset retirement obligations	13.4			5.8		—		19.2
Exploration expenses
Dry holes and previously suspended exploration costs	—			—		4.5		4.5
Geological and geophysical	6.5			—		4.3		10.8
Other exploration	5.1			0.3		17.0		22.4
	11.6			0.3		25.8		37.7
Undeveloped lease amortization	29.2			0.6		1.7		31.5
Total exploration expenses	40.8			0.9		27.5		69.2
Selling and general expenses	39.0			20.7		18.1		77.8
Other	12.4			(20.9	)	1.2		(7.3	)
Results of operations before taxes	255.8			64.3		(29.5	)	290.6
Income tax provisions (benefits)	55.5			17.6		(0.7	)	72.4
Results of operations (excluding corporate overhead and interest)	$	200.3		46.7		(28.8	)	218.2

¹ 2019 includes results attributable to a noncontrolling interest in MP GOM.

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

Corporate

Third quarter 2019 vs. 2018

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported net income of $0.3 million in the third quarter 2019 compared to net loss of $49.3 million in the 2018 quarter. The $49.6 million favorable variance is principally due to 2019 gains on forward swap commodity contracts ($63.2 million) compared to losses on forward contracts ($2.2 million) in the third quarter of 2018 and lower G&A expenses ($14.5 million), partially offset by 2018 Ecuador arbitration income ($26.0 million).

Nine months 2019 vs. 2018

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported a net loss of $97.0 million in the first nine months of 2019 compared to net loss of $96.7 million in the first nine months of 2018. The $0.3 million unfavorable variance is due to 2019 gains on forward swap commodity contracts ($121.2 million) compared to losses on forward contracts ($69.3 million) in 2018, offset by a 2018 income tax credit ($120.0 million, related to an IRS interpretation of the Tax Act), higher interest charges ($11.8 million), higher income tax charges ($7.1 million), foreign exchange losses ($6.4 million; versus an $5.9 million gain in 2018), Ecuador arbitration income in 2018 ($26.0 million), and lower OIL insurance dividend income ($3.5 million).

Discontinued Operations

The Company has presented its Malaysia E&P operations and former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.

Malaysia E&P operations reported earnings of $953.0 million in the third quarter of 2019 compared to earnings of $39.6 million in the comparable 2018 period. Results for the third quarter 2019 were favorable by $913.4 million primarily due to the recognition of a $960.0 million gain on the sale of Malaysia to PTT Exploration and Production Public Company Limited (PTTEP) (see Note D). The sale closed on July 10, 2019.

For the nine months ended September 30, 2019, Malaysia E&P operations reported earnings of $1,047.4 million compared to $188.8 million in the 2018 period. Results for the nine months ended September 30, 2019 were favorable by $858.6 million primarily as a result of the gain on sale of Malaysia of $960.0 million in the third quarter. Excluding the gain, Malaysia income was $101.4 million lower than the 2018 period principally due to lower revenues ($272.9 million), partially offset by lower operating expenses ($25.3 million), lower depreciation ($108.2 million) and lower income taxes ($44.7 million). Lower revenues are principally due to lower volumes sold. The lower depreciation is due to the cessation of charges as a result of the assets being classified as held for sale.

Financial Condition

Cash Provided by Operating Activities

Net cash provided by continuing operating activities was $1,153.2 million for the first nine months of 2019 compared to $601.4 million during the same period in 2018. The increased cash from operating activities is primarily attributable to higher cash revenues from the Gulf of Mexico acquisitions (see above). Changes in operating working capital from continuing operations increased cash by $40.3 million during the first nine months of 2019, compared to a decrease of $9.5 million in 2018.

Cash Used in Investing Activities

Cash used for property additions and dry holes, which includes amounts expensed, were $1,009.1 million and $797.6 million in the nine-month periods ended September 30, 2019 and 2018, respectively. Property additions in 2019 principally relate to exploration and development capital expenditures at Eagleford in the U.S., Kaybob in Canada and U.S. Gulf of Mexico. Cash used for the acquisition of oil and gas properties of $1,212.9 million is primarily attributable to acquisition of certain Gulf of Mexico assets from LLOG (see above).

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)

Financial Condition (contd.)

Cash Used in Investing Activities (contd.)

Total accrual basis capital expenditures, which includes $1,226.3 million for the LLOG acquisition were as follows:



	Nine Months Ended September 30,
(Millions of dollars)	2019		2018
Capital Expenditures
Exploration and production	$	2,320.6	784.8
Corporate	8.5		18.6
Total capital expenditures	$	2,329.1	803.4

A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.



	Nine Months Ended September 30,
(Millions of dollars)	2019		2018
Property additions and dry hole costs per cash flow statements	$	1,009.1	797.6
Acquisition of oil and gas properties	1,226.3		—
Geophysical and other exploration expenses	36.6		29.1
Capital expenditure accrual changes and other	57.1		(23.3	)
Total capital expenditures	$	2,329.1	803.4

The increase in capital expenditures in the exploration and production business in 2019 compared to 2018 was primarily attributable to higher development drilling activities in Eagle Ford Shale and the LLOG acquisition ($1,226.3 million).

Cash Provided by Financing Activities

Net cash used by financing activities was $961.4 million for the first nine months of 2019 compared to net cash used by financing activities of $136.9 million during the same period in 2018. In 2019, the cash provided by financing activities was principally from borrowings on our revolver and short-term loan ($1,575.0 million) to fund the LLOG acquisition (see above). These borrowings, along with the opening revolver balance ($325.0 million) of $1,900.0 million were repaid in July 2019 following the completion of the Malaysia divestment. The Company also used cash to buy back issued ordinary shares of $405.9 million. Total cash dividends to shareholders amounted to $125.4 million for the nine months ended September 30, 2019 compared to $129.8 million in the same period of 2018.

Working Capital

Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at September 30, 2019 was $101.5 million, $44.9 million lower than December 31, 2018, with the decrease primarily attributable to higher accounts payable ($227.4 million) and higher operating lease liabilities ($117.1 million; as a result of the implementation of ASC 842, Leases), partially offset by higher cash balances ($75.0 million) and higher accounts receivable ($230.8 million). The increase in accounts payable and receivable is attributable to the increased operating activity from the two Gulf of Mexico acquisitions.

Capital Employed

At September 30, 2019, long-term debt of $2,779.2 million had decreased by $330.1 million compared to December 31, 2018, as a result of paying down the outstanding balance on the revolving credit facility. A summary of capital employed at September 30, 2019 and December 31, 2018 follows.

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)

Financial Condition (contd.)

Capital Employed (contd.)



	September 30, 2019				December 31, 2018
(Millions of dollars)	Amount		%		Amount	%
Capital employed
Long-term debt	$	2,779.2	31.6	%	3,109.3	37.4	%
Total equity	6,025.8		68.4	%	5,197.6	62.6	%
Total capital employed	8,805.0		100.0	%	8,307.0	100.0	%
Total capital employed excluding noncontrolling interest	$	8,455.9	n/a		7,938.6	n/a

Cash and invested cash are maintained in several operating locations outside the United States. At September 30, 2019, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $132.1 million in Canada. In addition, $15.7 million of cash was held in the United Kingdom and $9.6 million was held in Brunei (both of which were reported in current Assets held for sale on the Company’s Consolidated Balance Sheet at September 30, 2019). In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.

Accounting changes and recent accounting pronouncements – see Note B

Outlook

Average worldwide crude oil prices at the end of October 2019 have decreased from the average prices during the third quarter of 2019. The Company expects its total oil and natural gas production to average 210,700 to 219,300 barrels of oil equivalent per day in the fourth quarter 2019 (including noncontrolling interest of 12,900 BOEPD). The Company currently anticipates total capital expenditures for the full year 2019 to be between $1.35 and $1.45 billion (excluding noncontrolling interest of $48 million).

The Company will primarily fund its remaining capital program in 2019 using operating cash flow but will supplement funding where necessary with borrowings under available credit facilities. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings might be required during the remainder of year to maintain funding of the Company’s ongoing development projects.

As of October 30, 2019, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:



Commodities	Contract or Location	Dates	Average Volumes per Day	Average Prices
U.S. Oil	West Texas Intermediate	Oct. – Dec. 2019	35,000 bbls/d	$60.51 per bbl.
U.S. Oil	West Texas Intermediate	Jan. – Dec. 2020	45,000 bbls/d	$56.42 per bbl.
Canada Natural Gas	NOVA Gas Transmission Ltd.	Oct. 2019	59 mmcf/d	C$2.81 per mcf
Canada Natural Gas	NOVA Gas Transmission Ltd.	Nov. 2019 – Mar. 2020	97 mmcf/d	C$2.71 per mcf
Canada Natural Gas	NOVA Gas Transmission Ltd.	Apr. 2020 – Dec. 2020	59 mmcf/d	C$2.81 per mcf

Forward-Looking Statements

This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to: the failure of the respective counterparties to perform their obligations under the relevant transaction agreements or the failure to satisfy all closing conditions, the volatility and level of crude oil and natural gas prices, the level and success rate of Murphy’s exploration programs, the Company’s ability to maintain production rates and replace reserves, customer demand for Murphy’s products, adverse foreign exchange movements, political and regulatory instability, adverse developments in the U.S. or global capital markets, credit markets or economies generally and uncontrollable natural hazards. For further discussion of risk factors, see Murphy’s 2018 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and page 37 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note L to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

There were commodity transactions in place at September 30, 2019, covering certain future U.S. crude oil sales volumes in 2019 and 2020. A 10% increase in the respective benchmark price of these commodities would have decreased the net receivable associated with these derivative contracts by approximately $83.1 million, while a 10% decrease would have increased the recorded receivable by a similar amount.

There were no derivative foreign exchange contracts in place at September 30, 2019.

ITEM 4. CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

During the quarter ended September 30, 2019, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Table of Contents

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Murphy is engaged in a number of legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

ITEM 1A. RISK FACTORS

The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in its 2018 Form 10-K filed on February 27, 2019. The Company has not identified any additional risk factors not previously disclosed in its 2018 Form 10-K report.

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

Issuer Purchase of Equity Securities:



Period	Total Number of Share Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs¹ (in thousands)
July 1 through July 31, 2019	—	$	—	—	$	200,000
August 1 through August 31, 2019	2,518,995	$	19.83	2,518,995	$	150,000
September 1 through September 30, 2019	2,501,564	$	22.37	2,501,564	$	94,000

¹In March 2019, the Company’s Board of Directors authorized a stock repurchase plan of up to $500 million of Murphy Common Stock. Maximum approximate values reported represent amounts at end of month. During the nine months ended September 30, 2019, the Company repurchased 16.4 million shares outstanding for $405.6 million. Subsequent to quarter end, the Company repurchased 4.3 million shares outstanding for $93.9 million, marking the completion of the $500 million share repurchase program.

ITEM 6. EXHIBITS

The Exhibit Index on page 39 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

Table of Contents

SIGNATURE

Pursuant to the 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.



	MURPHY OIL CORPORATION
	(Registrant)

	By	/s/ CHRISTOPHER D. HULSE
		Christopher D. Hulse,
		Vice President and Controller
		(Chief Accounting Officer and Duly Authorized Officer)

October 31, 2019

(Date)

Table of Contents

EXHIBIT INDEX



Exhibit No.

31.1		Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32		Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101. INS		XBRL Instance Document

101. SCH		XBRL Taxonomy Extension Schema Document

101. CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101. DEF		XBRL Taxonomy Extension Definition Linkbase Document

101. LAB		XBRL Taxonomy Extension Labels Linkbase Document

101. PRE		XBRL Taxonomy Extension Presentation Linkbase

Exhibits other than those listed above have been omitted since they are either not required or not applicable.

Nine Months Ended
September 30,

(Thousands of dollars)

Compensation charged against income before tax benefit

Related income tax benefit recognized in income