0000844965--12-312020FYfalse———1540220341530us-gaap:AccruedLiabilitiesCurrentAndNoncurrentus-gaap:AccruedLiabilitiesCurrentAndNoncurrent00008449652020-01-012020-12-31iso4217:USD00008449652020-06-30xbrli:shares00008449652021-03-0300008449652020-12-3100008449652019-12-31iso4217:USDxbrli:shares0000844965us-gaap:ProductMember2020-01-012020-12-310000844965us-gaap:ProductMember2019-01-012019-12-310000844965us-gaap:ProductMember2018-01-012018-12-310000844965us-gaap:ServiceMember2020-01-012020-12-310000844965us-gaap:ServiceMember2019-01-012019-12-310000844965us-gaap:ServiceMember2018-01-012018-12-3100008449652019-01-012019-12-3100008449652018-01-012018-12-310000844965us-gaap:RetainedEarningsMember2020-01-012020-12-310000844965tti:CommonStockValueMember2017-12-310000844965us-gaap:AdditionalPaidInCapitalMember2017-12-310000844965us-gaap:TreasuryStockMember2017-12-310000844965us-gaap:AccumulatedTranslationAdjustmentMember2017-12-310000844965us-gaap:RetainedEarningsMember2017-12-310000844965us-gaap:NoncontrollingInterestMember2017-12-3100008449652017-12-310000844965us-gaap:RetainedEarningsMember2018-01-012018-12-310000844965us-gaap:NoncontrollingInterestMember2018-01-012018-12-310000844965us-gaap:AccumulatedTranslationAdjustmentMember2018-01-012018-12-310000844965tti:CommonStockValueMember2018-01-012018-12-310000844965us-gaap:AdditionalPaidInCapitalMember2018-01-012018-12-310000844965us-gaap:TreasuryStockMember2018-01-012018-12-310000844965tti:CommonStockValueMember2018-12-310000844965us-gaap:AdditionalPaidInCapitalMember2018-12-310000844965us-gaap:TreasuryStockMember2018-12-310000844965us-gaap:AccumulatedTranslationAdjustmentMember2018-12-310000844965us-gaap:RetainedEarningsMember2018-12-310000844965us-gaap:NoncontrollingInterestMember2018-12-3100008449652018-12-310000844965us-gaap:RetainedEarningsMember2019-01-012019-12-310000844965us-gaap:NoncontrollingInterestMember2019-01-012019-12-310000844965us-gaap:AccumulatedTranslationAdjustmentMember2019-01-012019-12-310000844965tti:CommonStockValueMember2019-01-012019-12-310000844965us-gaap:AdditionalPaidInCapitalMember2019-01-012019-12-310000844965us-gaap:TreasuryStockMember2019-01-012019-12-310000844965us-gaap:RetainedEarningsMembersrt:CumulativeEffectPeriodOfAdoptionAdjustmentMember2018-12-310000844965srt:CumulativeEffectPeriodOfAdoptionAdjustmentMember2018-12-310000844965tti:CommonStockValueMember2019-12-310000844965us-gaap:AdditionalPaidInCapitalMember2019-12-310000844965us-gaap:TreasuryStockMember2019-12-310000844965us-gaap:AccumulatedTranslationAdjustmentMember2019-12-310000844965us-gaap:RetainedEarningsMember2019-12-310000844965us-gaap:NoncontrollingInterestMember2019-12-310000844965us-gaap:NoncontrollingInterestMember2020-01-012020-12-310000844965us-gaap:AccumulatedTranslationAdjustmentMember2020-01-012020-12-310000844965tti:CommonStockValueMember2020-01-012020-12-310000844965us-gaap:AdditionalPaidInCapitalMember2020-01-012020-12-310000844965us-gaap:TreasuryStockMember2020-01-012020-12-310000844965tti:CommonStockValueMember2020-12-310000844965us-gaap:AdditionalPaidInCapitalMember2020-12-310000844965us-gaap:TreasuryStockMember2020-12-310000844965us-gaap:AccumulatedTranslationAdjustmentMember2020-12-310000844965us-gaap:RetainedEarningsMember2020-12-310000844965us-gaap:NoncontrollingInterestMember2020-12-31xbrli:pure0000844965us-gaap:LineOfCreditMembersrt:ParentCompanyMember2020-12-310000844965srt:MinimumMemberus-gaap:FiniteLivedIntangibleAssetsMember2020-01-012020-12-310000844965srt:MaximumMemberus-gaap:FiniteLivedIntangibleAssetsMember2020-01-012020-12-310000844965tti:StandardLithiumMember2020-01-012020-12-310000844965tti:StandardLithiumMember2019-01-012019-12-310000844965tti:StandardLithiumMember2018-01-012018-12-310000844965tti:StandardLithiumMember2020-12-310000844965tti:StandardLithiumMember2019-12-310000844965us-gaap:BuildingMembersrt:MinimumMember2020-01-012020-12-310000844965us-gaap:BuildingMembersrt:MaximumMember2020-01-012020-12-310000844965srt:MinimumMemberus-gaap:MachineryAndEquipmentMember2020-01-012020-12-310000844965us-gaap:MachineryAndEquipmentMembersrt:MaximumMember2020-01-012020-12-310000844965srt:MinimumMemberus-gaap:VehiclesMember2020-01-012020-12-310000844965srt:MaximumMemberus-gaap:VehiclesMember2020-01-012020-12-310000844965srt:MinimumMemberus-gaap:OtherCapitalizedPropertyPlantAndEquipmentMember2020-01-012020-12-310000844965srt:MaximumMemberus-gaap:OtherCapitalizedPropertyPlantAndEquipmentMember2020-01-012020-12-310000844965tti:OffshoreDivisionMemberus-gaap:DiscontinuedOperationsDisposedOfBySaleMember2019-08-310000844965tti:OffshoreDivisionMemberus-gaap:DiscontinuedOperationsDisposedOfBySaleMember2018-03-010000844965tti:CompressionMember2020-01-012020-12-310000844965tti:OffshoreServicesMember2020-01-012020-12-310000844965tti:CompressionMember2019-01-012019-12-310000844965tti:OffshoreServicesMember2019-01-012019-12-310000844965tti:MaritechMember2019-01-012019-12-310000844965us-gaap:SeriesAPreferredStockMembertti:CompressionMember2019-01-012019-12-310000844965us-gaap:SeriesAPreferredStockMembertti:OffshoreServicesMember2019-01-012019-12-310000844965us-gaap:SeriesAPreferredStockMembertti:MaritechMember2019-01-012019-12-310000844965us-gaap:SeriesAPreferredStockMember2019-01-012019-12-310000844965tti:CompressionMember2018-01-012018-12-310000844965tti:OffshoreServicesMember2018-01-012018-12-310000844965tti:MaritechMember2018-01-012018-12-310000844965us-gaap:SeriesAPreferredStockMembertti:CompressionMember2018-01-012018-12-310000844965us-gaap:SeriesAPreferredStockMembertti:OffshoreServicesMember2018-01-012018-12-310000844965us-gaap:SeriesAPreferredStockMembertti:MaritechMember2018-01-012018-12-310000844965us-gaap:SeriesAPreferredStockMember2018-01-012018-12-310000844965tti:CompressionMember2020-12-310000844965tti:OffshoreServicesMember2020-12-310000844965tti:MaritechMember2020-12-310000844965tti:CompressionMember2019-12-310000844965tti:OffshoreServicesMember2019-12-310000844965tti:MaritechMember2019-12-310000844965tti:CompletionFluidsProductsDivisionMembercountry:US2020-01-012020-12-310000844965tti:CompletionFluidsProductsDivisionMembercountry:US2019-01-012019-12-310000844965tti:CompletionFluidsProductsDivisionMembercountry:US2018-01-012018-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:NonUsMember2020-01-012020-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:NonUsMember2019-01-012019-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:NonUsMember2018-01-012018-12-310000844965tti:CompletionFluidsProductsDivisionMember2020-01-012020-12-310000844965tti:CompletionFluidsProductsDivisionMember2019-01-012019-12-310000844965tti:CompletionFluidsProductsDivisionMember2018-01-012018-12-310000844965tti:WaterFlowbackServicesMembercountry:US2020-01-012020-12-310000844965tti:WaterFlowbackServicesMembercountry:US2019-01-012019-12-310000844965tti:WaterFlowbackServicesMembercountry:US2018-01-012018-12-310000844965tti:WaterFlowbackServicesMemberus-gaap:NonUsMember2020-01-012020-12-310000844965tti:WaterFlowbackServicesMemberus-gaap:NonUsMember2019-01-012019-12-310000844965tti:WaterFlowbackServicesMemberus-gaap:NonUsMember2018-01-012018-12-310000844965tti:WaterFlowbackServicesMember2020-01-012020-12-310000844965tti:WaterFlowbackServicesMember2019-01-012019-12-310000844965tti:WaterFlowbackServicesMember2018-01-012018-12-310000844965tti:InterdivisionEliminationsMembercountry:US2020-01-012020-12-310000844965tti:InterdivisionEliminationsMembercountry:US2019-01-012019-12-310000844965tti:InterdivisionEliminationsMembercountry:US2018-01-012018-12-310000844965tti:InterdivisionEliminationsMemberus-gaap:NonUsMember2020-01-012020-12-310000844965tti:InterdivisionEliminationsMemberus-gaap:NonUsMember2019-01-012019-12-310000844965tti:InterdivisionEliminationsMemberus-gaap:NonUsMember2018-01-012018-12-310000844965tti:InterdivisionEliminationsMember2020-01-012020-12-310000844965tti:InterdivisionEliminationsMember2019-01-012019-12-310000844965tti:InterdivisionEliminationsMember2018-01-012018-12-310000844965country:US2020-01-012020-12-310000844965country:US2019-01-012019-12-310000844965country:US2018-01-012018-12-310000844965us-gaap:NonUsMember2020-01-012020-12-310000844965us-gaap:NonUsMember2019-01-012019-12-310000844965us-gaap:NonUsMember2018-01-012018-12-310000844965tti:WaterFlowbackServicesMember2017-12-3100008449652017-01-012017-12-310000844965tti:CompletionFluidsProductsDivisionMember2020-10-012020-12-310000844965tti:WaterFlowbackServicesMember2020-10-012020-12-3100008449652019-07-012019-09-300000844965srt:MinimumMember2020-01-012020-12-310000844965srt:MaximumMember2020-01-012020-12-310000844965us-gaap:SecuredDebtMemberus-gaap:RevolvingCreditFacilityMember2020-12-310000844965us-gaap:SecuredDebtMemberus-gaap:RevolvingCreditFacilityMember2019-12-310000844965tti:TermLoanMemberus-gaap:SecuredDebtMember2020-12-310000844965tti:TermLoanMemberus-gaap:SecuredDebtMember2019-12-310000844965srt:ParentCompanyMember2020-12-310000844965srt:ParentCompanyMember2019-12-310000844965us-gaap:LineOfCreditMembersrt:ParentCompanyMemberus-gaap:RevolvingCreditFacilityMember2020-12-310000844965srt:ParentCompanyMemberus-gaap:LetterOfCreditMemberus-gaap:RevolvingCreditFacilityMember2020-12-310000844965tti:SwinglineLoanSublimitMembersrt:ParentCompanyMemberus-gaap:RevolvingCreditFacilityMember2020-12-310000844965us-gaap:LineOfCreditMembersrt:ParentCompanyMember2019-12-310000844965us-gaap:FederalFundsEffectiveSwapRateMembertti:AssetBasedLendingCreditAgreementMemberus-gaap:SecuredDebtMemberus-gaap:RevolvingCreditFacilityMember2018-09-102018-09-100000844965us-gaap:LondonInterbankOfferedRateLIBORMembertti:AssetBasedLendingCreditAgreementMemberus-gaap:SecuredDebtMemberus-gaap:RevolvingCreditFacilityMember2018-09-102018-09-100000844965srt:MinimumMemberus-gaap:LondonInterbankOfferedRateLIBORMemberus-gaap:SecuredDebtMembertti:AssetBasedLendingCreditAgreementMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-310000844965srt:MaximumMemberus-gaap:LondonInterbankOfferedRateLIBORMemberus-gaap:SecuredDebtMembertti:AssetBasedLendingCreditAgreementMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-310000844965srt:MinimumMemberus-gaap:BaseRateMemberus-gaap:SecuredDebtMembertti:AssetBasedLendingCreditAgreementMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-310000844965srt:MaximumMemberus-gaap:BaseRateMemberus-gaap:SecuredDebtMembertti:AssetBasedLendingCreditAgreementMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-310000844965srt:MinimumMembertti:AssetBasedLendingCreditAgreementMemberus-gaap:SecuredDebtMemberus-gaap:RevolvingCreditFacilityMember2018-09-102018-09-100000844965srt:MaximumMembertti:AssetBasedLendingCreditAgreementMemberus-gaap:SecuredDebtMemberus-gaap:RevolvingCreditFacilityMember2018-09-102018-09-100000844965tti:AssetBasedLendingCreditAgreementMemberus-gaap:SecuredDebtMemberus-gaap:RevolvingCreditFacilityMember2018-09-100000844965tti:TermLoanMembertti:TermCreditAgreementMemberus-gaap:LondonInterbankOfferedRateLIBORMemberus-gaap:SecuredDebtMember2018-09-102018-09-100000844965tti:TermLoanMembertti:TermCreditAgreementMemberus-gaap:BaseRateMemberus-gaap:SecuredDebtMember2018-09-102018-09-100000844965tti:TermLoanMembertti:TermCreditAgreementMemberus-gaap:SecuredDebtMember2018-09-102018-09-100000844965tti:TermLoanMembertti:TermCreditAgreementMemberus-gaap:SecuredDebtMember2018-09-100000844965tti:SwiftWaterEnergyServicesMember2018-02-132018-02-280000844965tti:SwiftWaterEnergyServicesMember2018-02-282018-02-280000844965tti:SwiftWaterEnergyServicesMember2018-02-270000844965tti:SwiftWaterEnergyServicesMember2019-12-310000844965tti:JRGOEnergyServicesLLCMember2018-12-062018-12-060000844965tti:JRGOEnergyServicesLLCMember2018-12-060000844965tti:OffshoreDivisionMember2018-03-020000844965tti:OffshoreDivisionMembertti:PromissoryNoteMember2018-03-020000844965tti:Within90DaysFollowingBondingAgreementClosingMember2020-12-3100008449652016-12-0900008449652016-12-092016-12-090000844965tti:Tetra2007LongTermIncentiveCompensationPlanMember2020-12-310000844965tti:Tetra2011LongTermIncentiveCompensationPlanMember2013-05-030000844965tti:Tetra2011LongTermIncentiveCompensationPlanMember2020-12-310000844965us-gaap:RestrictedStockMember2018-02-282018-02-280000844965tti:A2018EquityPlanMember2018-05-310000844965tti:A2018DirectorPlanMember2018-05-310000844965us-gaap:RestrictedStockMember2019-12-310000844965us-gaap:RestrictedStockMember2020-01-012020-12-310000844965us-gaap:RestrictedStockMember2020-12-310000844965us-gaap:InvestmentsMemberus-gaap:FairValueMeasurementsRecurringMember2020-12-310000844965us-gaap:InvestmentsMemberus-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMember2020-12-310000844965us-gaap:InvestmentsMemberus-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMember2020-12-310000844965us-gaap:FairValueInputsLevel3Memberus-gaap:InvestmentsMemberus-gaap:FairValueMeasurementsRecurringMember2020-12-310000844965us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:WarrantMember2020-12-310000844965us-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:WarrantMember2020-12-310000844965us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:WarrantMember2020-12-310000844965us-gaap:InvestmentsMemberus-gaap:FairValueMeasurementsRecurringMember2019-12-310000844965us-gaap:InvestmentsMemberus-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMember2019-12-310000844965us-gaap:InvestmentsMemberus-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMember2019-12-310000844965us-gaap:FairValueInputsLevel3Memberus-gaap:InvestmentsMemberus-gaap:FairValueMeasurementsRecurringMember2019-12-310000844965us-gaap:FairValueMeasurementsRecurringMemberus-gaap:WarrantMember2019-12-310000844965us-gaap:FairValueInputsLevel1Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:WarrantMember2019-12-310000844965us-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:WarrantMember2019-12-310000844965us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:WarrantMember2019-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:FairValueMeasurementsNonrecurringMember2019-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:FairValueMeasurementsNonrecurringMemberus-gaap:FairValueInputsLevel1Member2019-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsNonrecurringMember2019-12-310000844965us-gaap:FairValueInputsLevel3Membertti:CompletionFluidsProductsDivisionMemberus-gaap:FairValueMeasurementsNonrecurringMember2019-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:FairValueMeasurementsNonrecurringMember2019-01-012019-12-310000844965us-gaap:FairValueMeasurementsNonrecurringMembertti:WaterFlowbackServicesIntangibleAssetsMember2019-12-310000844965us-gaap:FairValueMeasurementsNonrecurringMemberus-gaap:FairValueInputsLevel1Membertti:WaterFlowbackServicesIntangibleAssetsMember2019-12-310000844965us-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsNonrecurringMembertti:WaterFlowbackServicesIntangibleAssetsMember2019-12-310000844965us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsNonrecurringMembertti:WaterFlowbackServicesIntangibleAssetsMember2019-12-310000844965us-gaap:FairValueMeasurementsNonrecurringMembertti:WaterFlowbackServicesIntangibleAssetsMember2019-01-012019-12-310000844965tti:WaterFlowbackServicesEquipmentMemberus-gaap:FairValueMeasurementsNonrecurringMember2019-12-310000844965tti:WaterFlowbackServicesEquipmentMemberus-gaap:FairValueMeasurementsNonrecurringMemberus-gaap:FairValueInputsLevel1Member2019-12-310000844965tti:WaterFlowbackServicesEquipmentMemberus-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsNonrecurringMember2019-12-310000844965us-gaap:FairValueInputsLevel3Membertti:WaterFlowbackServicesEquipmentMemberus-gaap:FairValueMeasurementsNonrecurringMember2019-12-310000844965tti:WaterFlowbackServicesEquipmentMemberus-gaap:FairValueMeasurementsNonrecurringMember2019-01-012019-12-310000844965us-gaap:FairValueMeasurementsNonrecurringMember2019-12-310000844965us-gaap:FairValueMeasurementsNonrecurringMemberus-gaap:FairValueInputsLevel1Member2019-12-310000844965us-gaap:FairValueInputsLevel2Memberus-gaap:FairValueMeasurementsNonrecurringMember2019-12-310000844965us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsNonrecurringMember2019-12-310000844965us-gaap:FairValueMeasurementsNonrecurringMember2019-01-012019-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:ProductMember2020-01-012020-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:ProductMember2019-01-012019-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:ProductMember2018-01-012018-12-310000844965tti:WaterFlowbackServicesMemberus-gaap:ProductMember2020-01-012020-12-310000844965tti:WaterFlowbackServicesMemberus-gaap:ProductMember2019-01-012019-12-310000844965tti:WaterFlowbackServicesMemberus-gaap:ProductMember2018-01-012018-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:ServiceMember2020-01-012020-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:ServiceMember2019-01-012019-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:ServiceMember2018-01-012018-12-310000844965tti:WaterFlowbackServicesMemberus-gaap:ServiceMember2020-01-012020-12-310000844965tti:WaterFlowbackServicesMemberus-gaap:ServiceMember2019-01-012019-12-310000844965tti:WaterFlowbackServicesMemberus-gaap:ServiceMember2018-01-012018-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:OperatingSegmentsMember2020-01-012020-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:OperatingSegmentsMember2019-01-012019-12-310000844965tti:CompletionFluidsProductsDivisionMemberus-gaap:OperatingSegmentsMember2018-01-012018-12-310000844965tti:WaterFlowbackServicesMemberus-gaap:OperatingSegmentsMember2020-01-012020-12-310000844965tti:WaterFlowbackServicesMemberus-gaap:OperatingSegmentsMember2019-01-012019-12-310000844965tti:WaterFlowbackServicesMemberus-gaap:OperatingSegmentsMember2018-01-012018-12-310000844965us-gaap:OperatingSegmentsMember2020-01-012020-12-310000844965us-gaap:OperatingSegmentsMember2019-01-012019-12-310000844965us-gaap:OperatingSegmentsMember2018-01-012018-12-310000844965us-gaap:CorporateMember2020-01-012020-12-310000844965us-gaap:CorporateMember2019-01-012019-12-310000844965us-gaap:CorporateMember2018-01-012018-12-310000844965tti:CorporateOverheadMember2020-01-012020-12-310000844965tti:CorporateOverheadMember2019-01-012019-12-310000844965tti:CorporateOverheadMember2018-01-012018-12-310000844965tti:CompletionFluidsProductsDivisionMember2020-12-310000844965tti:CompletionFluidsProductsDivisionMember2019-12-310000844965tti:WaterFlowbackServicesMember2020-12-310000844965tti:WaterFlowbackServicesMember2019-12-310000844965us-gaap:CorporateMember2020-12-310000844965us-gaap:CorporateMember2019-12-310000844965tti:CompressionMember2020-12-310000844965tti:CompressionMember2019-12-310000844965tti:CompressionMember2020-01-012020-12-310000844965tti:CompressionMember2019-01-012019-12-310000844965tti:CompressionMember2018-01-012018-12-310000844965tti:CanadaAndMexicoMember2020-01-012020-12-310000844965tti:CanadaAndMexicoMember2019-01-012019-12-310000844965tti:CanadaAndMexicoMember2018-01-012018-12-310000844965srt:SouthAmericaMember2020-01-012020-12-310000844965srt:SouthAmericaMember2019-01-012019-12-310000844965srt:SouthAmericaMember2018-01-012018-12-310000844965srt:EuropeMember2020-01-012020-12-310000844965srt:EuropeMember2019-01-012019-12-310000844965srt:EuropeMember2018-01-012018-12-310000844965srt:AfricaMember2020-01-012020-12-310000844965srt:AfricaMember2019-01-012019-12-310000844965srt:AfricaMember2018-01-012018-12-310000844965tti:AsiaAndOtherMember2020-01-012020-12-310000844965tti:AsiaAndOtherMember2019-01-012019-12-310000844965tti:AsiaAndOtherMember2018-01-012018-12-310000844965country:US2020-12-310000844965country:US2019-12-310000844965tti:CanadaAndMexicoMember2020-12-310000844965tti:CanadaAndMexicoMember2019-12-310000844965srt:SouthAmericaMember2020-12-310000844965srt:SouthAmericaMember2019-12-310000844965srt:EuropeMember2020-12-310000844965srt:EuropeMember2019-12-310000844965srt:AfricaMember2020-12-310000844965srt:AfricaMember2019-12-310000844965tti:AsiaAndOtherMember2020-12-310000844965tti:AsiaAndOtherMember2019-12-310000844965tti:OffshoreServicesMember2020-12-310000844965tti:OffshoreServicesMember2019-12-310000844965tti:CSICompresscoMembertti:SpartanEnergyPartnersLPMemberus-gaap:SubsequentEventMembertti:SpartanEnergyPartnersLPMember2021-01-292021-01-290000844965tti:CSICompresscoMembertti:SpartanEnergyPartnersLPMemberus-gaap:SubsequentEventMember2021-01-292021-01-290000844965tti:CSICompresscoMembertti:SpartanEnergyPartnersLPMemberus-gaap:SubsequentEventMember2021-01-290000844965us-gaap:SubsequentEventMember2021-01-292021-01-290000844965us-gaap:SubsequentEventMember2021-01-29
PART I
Item 1. Business.
The financial statements presented in this Annual Report are the consolidated financial statements of TETRA Technologies, Inc., a Delaware corporation and its subsidiaries. When the terms “TETRA,” “the Company,” “we,” “us,” or “our” are used in this document, those terms refer to TETRA Technologies, Inc. and its consolidated subsidiaries.
TETRA is a Delaware corporation incorporated in 1981. Our corporate headquarters are located at 24955 Interstate 45 North, The Woodlands, Texas, 77380. Our phone number is 281-367-1983 and our website is www.tetratec.com. Our common stock is traded on the New York Stock Exchange (the “NYSE”) under the symbol “TTI.”
Our Corporate Governance Guidelines, Code of Business Conduct, Code of Ethics for Senior Financial Officers, Audit Committee Charter, Compensation Committee Charter, and Nominating and Corporate Governance Committee Charter, as well as our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, and all amendments to those reports are all available, free of charge, on our website at www.tetratec.com as soon as practicable after we file the reports with the SEC. Information contained on or connected to our website is not, and shall not be deemed to be, a part of this Annual Report on Form 10-K or incorporated into any other filings with the SEC. The documents referenced above are available in print at no cost to any stockholder who requests them from our Corporate Secretary.
About TETRA
TETRA Technologies, Inc., together with its consolidated subsidiaries, is a leading, geographically diversified oil and gas services company, focused on completion fluids and associated products and services, comprehensive water management, frac flowback and production well testing. Prior to the closing of the GP Sale (as defined below) on January 29, 2021, we operated in three reporting segments organized into three Divisions. Following the closing of the GP Sale, our products and services are delivered through two reporting segments organized into two Divisions - Completion Fluids & Products and Water & Flowback Services.
Our Completion Fluids & Products Division manufactures and markets clear brine fluids, additives, and associated products and services to the oil and gas industry for use in well drilling, completion, and workover operations in the United States and in certain countries in Latin America, Europe, Asia, the Middle East and Africa. The Division also markets liquid and dry calcium chloride products manufactured at its production facilities or purchased from third-party suppliers to a variety of markets outside the energy industry.
Our Water & Flowback Services Division provides onshore oil and gas operators with comprehensive water management services. The Division also provides frac flowback, production well testing, offshore rig cooling, and other associated services in many of the major oil and gas producing regions in the United States and Mexico, as well as in oil and gas basins in certain countries in Latin America, Europe, and the Middle East.
We continue to pursue a long-term growth strategy that includes expanding our core businesses, domestically and internationally, through the introduction of new technology, organic growth and accretive acquisitions.
Products and Services
Completion Fluids & Products Division
Liquid calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, sodium bromide, and blends of such products manufactured by our Completion Fluids & Products Division are referred to as clear brine fluids (“CBFs”) in the oil and gas industry. CBFs are salt solutions that have variable densities and are used to control bottom-hole pressures during oil and gas completion and workover operations. The Division sells CBFs and various CBF additives to U.S. and foreign oil and gas exploration and production companies and to other companies that service customers in the oil and gas industry.
The Completion Fluids & Products Division provides both stock and custom-blended CBFs based on each customer’s specific needs and the proposed application. It provides a broad range of associated CBF services, including: on-site fluids filtration, handling and recycling; wellbore cleanup; custom fluids blending; and fluid management services. The Division’s flagship CBF technology, TETRA CS Neptune® completion fluids, are high-density monovalent and divalent fluids that are free of undissolved solids, zinc, priority pollutants, and formate ions. They were developed by TETRA to be environmentally friendly alternatives to traditional zinc bromide high-density completion fluids and environmentally friendly and cost-effective alternatives to cesium formate high-density completion fluids, all of which are used in well completion and workover operations, as well as a low-solids reservoir drilling fluids.
The Completion Fluids & Products Division offers to repurchase, or “buy-back”, certain used CBFs from customers, which can be reconditioned and recycled. Selling used CBFs back to us reduces the net cost of the CBFs to customers and minimizes our customers’ need to dispose of used fluids. We recondition used CBFs through filtration, blending and the use of proprietary chemical processes, and then market the reconditioned CBFs.
By blending different CBFs and using various additives, we are able to modify the specific density, crystallization temperature, and chemical composition of the CBFs as required to meet our customers’ specific needs. The Division’s fluid engineering personnel determine the optimal CBF blend for a customer’s particular application to maximize its effectiveness and lifespan. Our filtration services use a variety of techniques and equipment to remove particulates from CBFs at the customer’s site so the CBFs can be reused. Filtration also enables recovery of a greater percentage of used CBFs for reconditioning.
The Completion Fluids & Products Division manufactures liquid and dry calcium chloride and liquid calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide for distribution, primarily into energy markets. Liquid and dry calcium chloride are also sold into water treatment, industrial, cement, food processing, road maintenance, ice melt, agricultural, and consumer products markets. Sodium bromide is also sold into industrial water treatment markets, where it is used as a biocide in recirculated cooling tower waters and in other applications.
Our calcium chloride manufacturing facilities are located in the United States and Finland. In the United States, we manufacture liquid calcium chloride products at four manufacturing plant facilities. Liquid and flake calcium chloride are also produced at our Kokkola, Finland plant. We operate our European calcium chloride operations under the name TETRA Chemicals Europe. We also manufacture liquid calcium chloride at our facilities in Parkersburg, West Virginia and Lake Charles, Louisiana, and we have two solar evaporation facility locations located in San Bernardino County, California, that produce liquid calcium chloride and sodium chloride from underground brine reserves, which are replenished naturally. Our calcium chloride production facilities have a combined production capacity of approximately 1.0 million equivalent liquid tons per year. We also acquire calcium chloride inventory from other producers.
Our Completion Fluids & Products Division manufactures liquid calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide at our West Memphis, Arkansas facility. A proprietary process applied at this facility uses bromine and zinc to manufacture zinc bromide. This facility also uses proprietary processes to manufacture calcium bromide and sodium bromide and to recondition and upgrade used CBFs that we have repurchased from our customers.
Water & Flowback Services Division
Our Water & Flowback Services Division provides a wide variety of water management services that support hydraulic fracturing in unconventional well completions for domestic onshore oil and gas operators. These services include fresh and produced water analysis, treatment and recycling, blending and distribution, storage and pit lining, transfer, engineering, and environmental risk mitigation. The Water & Flowback Services Division’s patented and patent-pending equipment and processes include advanced hydrocyclones for sand management, certain produced- and fresh-water blending technologies, and TETRA Steel™ 1200 rapid deployment water transfer system. The Water & Flowback Services Division seeks to design sustainable solutions that meet the unique needs of each customer in order to maximize operational performance and efficiency, and minimize the use of fresh water. These include tailored “Last Mile” infrastructure - which consists of water storage ponds, movable storage tanks, a network of water transfer lines including poly pipe and TETRA Steel™ lay-flat hose, automated transfer and blending of produced water, and water treatment and recycling systems including the TETRA SwiftWater Automated Treatment (SWAT™) system that chemically treats produced water through a clarification process and the oil recovery from produced water via the TETRA Oil Recovery After Production Technology (Orapt™) mobile oil
separation system to transfer water around well pads in a safe, efficient and environmentally responsible manner. Automation has also been deployed throughout 2020 across the TETRA water management portfolio to reduce health, safety and environmental risks and enhance reliability and cost-effectiveness.
Our Water & Flowback Services Division also provides frac flowback services, early production facilities and services, production well testing services, offshore rig cooling services, and other associated services, including well flow management and evaluation services that enable operators to quantify oil and gas reserves, optimize oil and gas production and minimize oil and gas reservoir damage. In certain basins, water, sand, and other abrasive materials commonly accompany the initial production of natural gas or oil, often under high-pressure and high-temperature conditions and, in some cases, from reservoirs containing high levels of hydrogen sulfide gas. The Water & Flowback Services Division provides the specialized equipment and qualified personnel to address these impediments to production. Early production services typically include sophisticated evaluation techniques for reservoir management, including unconventional shale reservoir exploitation and optimization of well workover programs. Frac flowback and production well testing services may include well control, well cleanup and laboratory analysis. These services are used in the completion process after hydraulic fracturing and in the production phase of oil and gas wells.
This Division maintains one of the largest fleets of high-pressure production testing equipment in the United States, including equipment designed to work in environments where high levels of hydrogen sulfide gas are present. The Division has domestic operating locations in Colorado, Louisiana, New Mexico, North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming. The Division also has locations in certain countries in Latin America, Europe, and the Middle East.
Former Compression Division
Our former Compression Division provided compression services and equipment for natural gas and oil production, gathering, artificial lift, transmission, processing and storage. Our former Compression Division’s operations were conducted through our partially-owned CSI Compressco LP (“CCLP”) subsidiary. Through one of our former wholly-owned subsidiaries, CSI Compressco GP LLC (f/k/a CSI Compressco GP Inc.) (the “general partner”), we managed and controlled CCLP, and accordingly, we consolidated CCLP’s results of operations in our consolidated results of operations through December 31, 2020. As of December 31, 2020, common units held by the public represented approximately a 65% common unit ownership interest in CCLP. On January 29, 2021, we entered into the Purchase and Sale Agreement with Spartan Energy Partners, LP and Energy Holdco, LLC (together, “Spartan”) pursuant to which we sold the general partner of CCLP, including the incentive distribution rights (“IDRs”) in CCLP and approximately 23.1% of the outstanding limited partner interests in CCLP, in exchange for a combination of $13.4 million in cash paid at closing, $0.5 million in cash payable on the six-month anniversary of the closing and $3.1 million in contingent consideration in the form of cash and/or CCLP common units if CCLP achieves certain financial targets on or before December 31, 2022. We were required to use all net cash proceeds received at closing from the sale to repay borrowings under our Term Credit Agreement. Following the closing of the transaction, we retained approximately 11.1% of the outstanding CCLP common units. Throughout this Annual Report, we refer to the transaction with Spartan as the “GP Sale.” We have reflected the operations of our former Compression Division as discontinued operations for all periods presented. See Note 3 - “Discontinued Operations” and Note 18 - “Subsequent Event” in the Notes to Consolidated Financial Statements for further information.
Sources of Raw Materials
Our Completion Fluids & Products Division manufactures calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide for sale to its customers. The Division also recycles used calcium bromide and zinc bromide CBFs repurchased from its oil and gas customers.
The Completion Fluids & Products Division manufactures liquid calcium chloride, either from underground brine or by reacting hydrochloric acid with limestone. We produce calcium chloride and sodium chloride at our two facilities in San Bernardino County, California, by solar evaporation of pumped underground brine reserves that contain calcium chloride. The underground reserves of this brine are deemed adequate to supply our foreseeable need for calcium chloride at those plants. The Division also purchases liquid and dry calcium chloride from a number of U.S. and foreign chemical manufacturers.
The Completion Fluids & Products Division’s primary sources of hydrochloric acid are co-product streams obtained from chemical manufacturers. Substantial quantities of limestone are also consumed when converting
hydrochloric acid into calcium chloride. Currently, hydrochloric acid and limestone are generally available from multiple sources.
To produce calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide at our West Memphis, Arkansas facility, we use bromine, hydrobromic acid, zinc, ammonia water and lime as raw materials. There are multiple sources of zinc that we can use in the production of zinc bromide and zinc calcium bromide. We have a long-term supply agreement with Lanxess, AG (Lanxess”) under which the Completion Fluids & Products Division purchases its requirements of raw material bromine from Lanxess’ Arkansas bromine production facilities.
The Completion Fluids & Products Division also owns a calcium bromide manufacturing plant near Magnolia, Arkansas, which was constructed in 1985. This plant was acquired in 1988 and is not operable. We currently lease over 27,000 acres of brine leases in the vicinity of this plant, which contain bromine and lithium. While this plant is designed to produce calcium bromide, it could be modified to produce elemental bromine or select bromine compounds. Development of the brine field, construction of necessary pipelines and reconfiguration of the plant would require a substantial capital investment. The long-term Lanxess bromine supply agreement discussed above provides a secure supply of bromine to support the Division’s current operations. We do, however, continue to evaluate our strategy related to the Magnolia, Arkansas, assets and their future development. Lanxess has certain rights to participate in future development of the Magnolia, Arkansas assets. In addition, we are party to agreements with Standard Lithium Ltd. (“Standard Lithium”) (TSXV:SLL), under which Standard Lithium has the right to explore, produce and extract lithium in our Arkansas leases as well as additional potential resources in the Mojave region (San Bernardino County) of California. See Note 2 - “Summary of Significant Accounting Policies” and Note 15 - “Fair Value Measurements” in the Notes to Consolidated Financial Statements for further information.
The Water & Flowback Services Division purchases water management and production testing equipment and components from third-party manufacturers.
Market Overview and Competition
Our operations are highly dependent upon the demand for, and production of, natural gas and oil in the various domestic and international locations in which we operate, and were significantly affected by the unprecedented impact of the COVID-19 pandemic. Demand for products and services of our Completion Fluids & Products Division remained resilient despite pandemic impacts on commodity prices. Recent oil price volatility and much lower oil prices during the second and third quarters of 2020 particularly affected domestic onshore demand for our Water & Flowback Services Division services. For example, in 2020 West Texas Intermediate oil prices ranged from a high of $63.27 per barrel in January 2020 to a low of negative $39.68 per barrel in April 2020.
Completion Fluids & Products Division
Our Completion Fluids & Products Division provides its products and services to oil and gas exploration and production companies in the United States and certain foreign markets, and to other customers that service such companies. Current areas of market presence include the onshore U.S., the U.S. Gulf of Mexico, the North Sea, Mexico and certain countries in South America, Europe, Asia, the Middle East and Africa. Customers with deepwater operations frequently use high volumes of CBFs, which can be subject to harsh downhole conditions, such as high pressure and high temperatures. Demand for CBF products is generally driven by offshore completion and workover activity.
The Completion Fluids & Products Division’s principal competitors in the sale of CBFs to the oil and gas industry are other major international drilling fluids and energy services companies, to many of which we provide products and services. This market is highly competitive and competition is based primarily on service, availability, and price. Customers of the Completion Fluids & Products Division include significant oilfield service companies, major and independent U.S. and international oil and gas producers, and U.S. and international chemical providers. The Division also sells its CBF products through various distributors.
The Completion Fluids & Products Division’s liquid and dry calcium chloride products have a wide range of uses outside the energy industry. Non-energy market segments where these products are used include water treatment, industrial, food processing, road maintenance, ice melt, agricultural, and consumer products. We also sell sodium bromide into industrial water treatment markets as a biocide under the BioRid® tradename. Most of these markets are highly competitive. The Completion Fluids & Products Division’s European calcium chloride operations market our calcium chloride products to certain European markets. Our principal competitors in the non-
energy related calcium chloride markets include Occidental Chemical Corporation and Vitro in North America and NedMag in Europe.
Water & Flowback Services Division
The Water & Flowback Services Division provides comprehensive water management and frac flowback services to a wide-range of onshore oil and gas operators located in all active North America unconventional oil and gas basins.
The Division also provides frac flowback services, early production facilities and services, production well testing services, sand filtration, and other associated services in various domestic and international locations, including well flow management and evaluation services that enable operators to quantify oil and gas reserves, optimize oil and gas production, and minimize oil and gas reservoir production damage.
The water management, flowback, and production testing markets are highly competitive, and competition is based on availability of appropriate equipment and qualified personnel, as well as price, quality of service, and safety record. The Division’s skilled personnel, operating procedures, integrated closed-loop water management solution, automation systems, and safety record give us a competitive advantage. Competition in the U.S. water management markets includes Select Energy and various regional companies, while competition in onshore U.S. production testing markets is primarily dominated by numerous small, privately owned operators. Halliburton, and Schlumberger are competitors in the international production testing markets we serve although we provide these services to their customers on a subcontract basis from time to time. Customers for the Water & Flowback Services Division include major integrated and independent U.S. and international oil and gas producers that are active in the areas in which we operate.
No single customer provided 10% or more of our total consolidated revenues during the years ended December 31, 2020 or 2018. One customer provided more than 10% of our total consolidated revenues during the year ended December 31, 2019.
Other Business Matters
Human Capital Management
We collaborate as a team to execute for each other, our customers, and our shareholders. As of December 31, 2020, we had approximately 1,800 people worldwide, including approximately 730 employees of CCLP. None of our U.S. employees are presently covered by a collective bargaining agreement. Our employees outside the U.S. are generally members of labor unions and associations in the countries in which they are employed. We believe that our relations with our employees are good.
Diversity and Inclusion
The diversity of our global workforce stimulates creativity and innovation as we use our collective talents to develop unique solutions to address the world's energy challenges. Our executive management sponsored Diversity & Inclusion Committee focuses on sharing information and promoting key initiatives across the company to educate and create awareness about the importance of a diverse and inclusive culture. The committee also assists the talent management group to attract, retain, develop, and reward a high-performing and diverse workforce, provide forums and sponsor training activities to share best practices concerning diversity and inclusion education, and develop communication platforms to share information about diversity and inclusion and promote the committee’s activities.
Career Development
The board of directors, the chief executive officer, and the director of Human Resources, evaluate, from time to time each year, executive development and succession planning to prepare us for future success. The succession planning process covers all senior management positions and certain other key positions. This review of executive talent determines readiness to take on additional leadership roles and identifies developmental opportunities needed to prepare our executives for greater responsibilities. Our short and long-term business strategy is considered when evaluating candidates and their skills.
Compensation and Benefits
The Company’s compensation programs are designed to incentivize performance, maximize returns, and build shareholder value. We work with consultants to benchmark our compensation and benefits programs to help us offer competitive compensation packages to attract and retain high-performing talent. We also offer competitive benefits to attract and retain exceptional talent.
Safety
Recognizing that safety, service quality, and environmental protection are conditions of employment, all employees and contractors are responsible for their safety, the safety of those around them, the quality of their work, and protection of the environment. As part of our safety-focused culture, it is customary that each meeting starts with an employee-led safety moment.
To ensure our work remains safe and of the highest quality, the Company has a comprehensive HSEQ Management System and program designed to improve the capacity of the organization by controlling worksite risks, developing proper work practices and procedures, and empowering employees with stop-work authority if they observe unsafe conditions, omissions, errors, or actions that could result in safety or environmental incidents, or product and service quality issues. If an incident takes place, we investigate all serious occurrences to root causes and implement corrective actions to ensure we expand our capacity to operate safely.
Driving is one of the highest exposure activities that we undertake in our day-to-day operations. We maintain a fleet of DOT and non-DOT vehicles and provide positive, real-time behavior feedback to our drivers via real-time monitors. Coupled with Journey Management, vehicle selection guidelines, and driver training, we have a comprehensive approach to reducing our driving exposure and incidents.
Proprietary Technology and Trademarks
As of December 31, 2020, we owned or licensed thirty-three issued U.S. patents and had fifteen patent applications pending in the United States. We also had thirty-six owned or licensed patents and forty-five patent applications pending in various other countries. The foreign patents and patent applications are primarily foreign counterparts to certain of our U.S. patents or patent applications. The issued patents expire at various times through 2037. We have elected to maintain certain other internally developed technologies, know-how, and inventions as trade secrets. While we believe that our patents and trade secrets are important to our competitive positions in our businesses, we do not believe any one patent or trade secret is essential to our success.
It is our practice to enter into confidentiality agreements with key employees, consultants and third parties to whom we disclose our confidential and proprietary information, and we have typical policies and procedures designed to maintain the confidentiality of such information. There can be no assurance, however, that these measures will prevent the unauthorized disclosure or use of our trade secrets and expertise, or that others may not independently develop similar trade secrets or expertise.
We sell various products and services under a variety of trademarks and service marks, some of which are registered in the United States or other countries.
Health, Safety, and Environmental Affairs Regulations
Our service and sales operations and manufacturing plants are subject to stringent and complex U.S. and foreign health, safety, and environmental laws and regulations. Although we are committed to conducting all of our operations under the highest standards of safety and respect for the environment, risks of substantial costs and liabilities pursuant to such laws and regulations are inherent in certain of our operations and in the development and handling of certain products and equipment produced or used at our plants, well locations, and worksites. Because of these risks, there can be no assurance that significant costs and liabilities will not be incurred now or in the future. Changes in environmental and health and safety laws and regulations could subject us to more rigorous standards and could affect demand for our customers’ products which in turn would impact demand for our products. We cannot predict the extent to which our operations may be affected by any changes to existing laws, regulations and enforcement policies, new interpretations of existing laws, regulations and policies, or any new laws, regulations, or policies promulgated in the future.
We are subject to numerous federal, state, local, and foreign laws and regulations relating to health, safety, and the environment, including regulations regarding air emissions, wastewater and storm water discharges, and the disposal of certain hazardous and nonhazardous wastes. Compliance with such laws and regulations may
expose us to significant costs and liabilities, and cause us to incur significant capital expenditures in our operations. Failure to comply with these laws and regulations or associated permits may result in the assessment of administration, civil or criminal fines and penalties, the imposition of other corrective action obligations or other injuctive relief, or both.
Our operations in the United States are subject to various evolving environmental laws and regulations that are enforced by the U.S. Environmental Protection Agency (“EPA”); the Bureau of Safety and Environmental Enforcement (“BSEE”) of the U.S. Department of the Interior; the U.S. Coast Guard; and various other federal, state, and local environmental authorities. Similar laws and regulations, designed to protect the health and safety of our employees and visitors to our facilities, are enforced by the U.S. Occupational Safety and Health Administration, and other state and local agencies and authorities. The primary environmental laws and regulations applicable to our operations include: (i) the Federal Water Pollution Control Act of 1972 (the “Clean Water Act”); (ii) the Resource Conservation and Recovery Act of 1976; (iii) the Clean Air Act of 1977 (“CAA”); (iv) the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”); (v) the Superfund Amendments and Reauthorization Act of 1986; (vi) the Toxic Substances Control Act of 1976; (vii) the Hazardous Materials Transportation Act of 1975; and (viii) and the Pollution Prevention Act of 1990. Our operations outside the United States are subject to various foreign governmental laws and regulations relating to the environment, health and safety, and other regulated activities in the countries in which we operate.
Our operations routinely involve the handling of natural gas, oil, other petroleum products, and produced water. Hydrocarbons or hazardous and nonhazardous wastes may have been released during our operations, by third parties on wellhead sites where we provide services or store our equipment, or on or under other locations where wastes have been taken for disposal. Although most wastes associated with the exploration, development and production of oil and natural gas are currently exempt from the more stringent hazardous waste regulations under RCRA and its state analogs, it is possible that some of the material we handle now or may handle in the future may be subject to regulation under RCRA as a hazardous waste. Additionally, we cannot assure you that such materials will not be subject to more stringent requirements or characterized as hazardous wastes in the future. Separately, properties where such hydrocarbons and/or wastes are released or disposed of may be subject to investigatory, remediation, and monitoring requirements under foreign, federal, state, and local environmental laws and regulations. CERCLA and comparable state laws and regulations impose strict, joint, and several liabilities without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of a disposal site where a hazardous substance release occurred and any person that transported, disposed of, or arranged for the transport or disposal of such hazardous substances released at a site. Under CERCLA, such persons may be liable for the costs of remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.
The CAA and its implementing regulations, and comparable state laws and regulations, regulate the emissions of air pollutants from various industrial sources and impose monitoring and reporting requirements. These laws and regulations impose limits on the levels of various substances that may be emitted into the atmosphere. For example, in June 2016, the EPA adopted regulations under its New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants that establish air emission controls for natural gas and natural gas liquids production, processing and transportation activities. These rules establish specific requirements associated with volatile organic compounds and methane emissions from certain hydraulically fractured natural gas wells, production-related wet seal and reciprocating compressors, and pneumatic controllers and storage vessels, and further require that most hydraulically fractured natural gas wells use so-called “green” completions. While the EPA under the Trump Administration finalized rules to rescind or modify certain of these requirements in September 2020, including rescission of the methane-specific requirements applicable to sources in the production and processing segments of the oil and gas industry, various states and industry and environmental groups are separately challenging the EPA’s June 2016 standards and its September 2020 final rule. Moreover, notwithstanding the current court challenges, the EPA under the Biden Administration is expected to reconsider the September 2020 final rule, which could result in more stringent rulemakings. While we do not believe that compliance with current regulatory requirements will have a material adverse effect on our business or operations, additional or more stringent regulations could impose new air permitting or pollution control requirements on our equipment that could require us to incur material costs.
In accordance with Section 402 of the Clean Water Act, the EPA is authorized to issue National Pollutant Discharge Elimination System (“NPDES”) General Permits to regulate offshore discharges in the Gulf of Mexico which includes Treatment, Completion and Workover (“TCW”) fluids. Our operations include providing services and
materials to oil and gas operators for the use of TCW fluids in the Gulf of Mexico. The EPA’s current NPDES permit for oil and gas operations in the federal waters of the Gulf of Mexico requires oil and gas operators to assess the toxicity characteristics of TCW fluids that are discharged and to submit the assessment results through 2021. Although the results of such assessments are not expected to have a material adverse impact on our business or operations, they could result in additional restrictions on oil and gas operation in the Gulf of Mexico under the Clean Water Act, which could have an indirect effect on us. In addition, the Clean Water Act, and comparable state laws and regulations thereunder, also prohibit the discharge of pollutants into regulated waters without a permit, including industrial wastewater discharges and storm water runoff, and establish limits on the levels of pollutants contained in such discharges.
The modification or reinterpretation of existing environmental laws or regulations, the more vigorous enforcement of existing environmental laws or regulations, or the adoption of new environmental laws or regulations could adversely affect oil and natural gas exploration and production operations, which in turn could have an adverse effect on us.
We maintain various types of insurance intended to reimburse us for certain costs in the event of an accident, including an explosion or similar event, involving our onshore and offshore operations. Our insurance program is reviewed not less than annually with our insurance brokers and underwriters. As part of our insurance program for offshore operations, we maintain Commercial General Liability, Protection and Indemnity, and Excess Liability policies that provide third-party liability coverage, including but not limited to death and personal injury, collision, damage to property including fixed and floating objects, pollution, and wreck removal up to the applicable policy limits. However, such insurance policies may not cover, or may only partially cover, certain losses or claims, which could result in a material adverse effect on our business and operations.
Item 1A. Risk Factors.
Certain Business Risks
Although it is not possible to identify all of the risks we encounter, we have identified the following significant risk factors that could affect our actual results and cause actual results to differ materially from any such results that might be projected, forecasted, or estimated by us in this Annual Report.
Market Risks
The demand and prices for our products and services are affected by several factors, including the supply, demand, and prices for oil and natural gas.
Demand for our services and products is particularly sensitive to the level of exploration, development, and production activity of, and the corresponding capital spending by, oil and natural gas companies. The level of exploration, development, and production activity is directly affected by oil and natural gas prices, which historically have been volatile and are likely to continue to be volatile. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of other economic factors that are beyond our control.
Although oil prices steadily rose during late 2020 and early 2021, they fell during early 2020, with West Texas Intermediate oil prices dropping from a high of $63.27 per barrel in January 2020 to a low of negative $39.68 per barrel in April 2020. The West Texas Intermediate price averaged $39.16 per barrel during 2020. Over this same period, U.S. natural gas prices have also been volatile, with the Henry Hub price ranging from a high of $3.14 per million British thermal units (“MMBtu”) in October 2020 to a low of $1.33 per MMBtu in September 2020. As of March 3, 2021, the price of West Texas Intermediate oil was $61.28 per barrel and the Henry Hub price for natural gas was $2.82 per MMBtu. The prolonged volatility and low levels of oil and natural gas prices and persisting supply and demand imbalances have depressed levels of exploration, development, and production activity, and if the drop in oil and natural gas prices we have experienced in 2020 continues or further declines and the supply and demand imbalances persist, there would be a material adverse effect on our business, consolidated results of operations, and consolidated financial condition. Should current market conditions worsen for an extended period of time, we may be required to record additional asset impairments. Such potential impairment charges could have a material adverse impact on our operating results.
Factors affecting the prices of oil and natural gas include: the level of supply and demand for oil and natural gas, worldwide; governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; weather conditions, natural disasters, and health or similar issues, such as pandemics or epidemics; worldwide political, military, and economic conditions; the ability or willingness of the Organization of Petroleum Exporting Countries (“OPEC”) and non-OPEC countries, such as Russia, to set and maintain oil production levels; the levels of oil production in the U.S. and by other non-OPEC countries; oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas; the cost of producing and delivering oil and natural gas; and acceleration of the development of, and demand for, alternative energy sources.
The COVID-19 pandemic has had, or may in the future have, certain negative impacts on our business, and such impacts have had, or may in the future have, an adverse effect on our business, our financial condition, results of operations, or liquidity.
The COVID-19 pandemic and the resulting economic impact have had a significant negative impact on the oil and gas industry. The deterioration in demand for oil caused by the pandemic, coupled with oil oversupply, has had, and is reasonably likely to continue to have, an adverse impact on the demand for our products and services. The public health crisis caused by the COVID-19 pandemic, and the measures that have been taken or that may be taken in the future by governments, various regulatory agencies, our customers and our suppliers, have had, or may in the future have, certain negative impacts on our financial condition, results of operations, and liquidity, including, without limitation, the following:
•demand for our products and services declining as our customers continue to adjust their operations in response to lower oil and gas prices;
•actions undertaken by national, state and local governments and health officials to contain COVID-19 or treat its effects. In response to various governmental directives, at points we have required most office-based employees, including most employees based at our headquarters in The Woodlands, Texas, to work remotely. We may experience reductions in productivity and disruptions to our business routines while work-from-home arrangements remain in place;
•We could encounter logistical complications and increased costs adapting our disclosure controls and procedures and our internal control over financial reporting in a changing environment that includes work-from-home arrangements and furloughs. In the future we may encounter operational challenges or disruptions stemming from the pandemic that require us to implement new or enhanced internal controls to mitigate the risks of operating in a remote environment or increased risks of material misstatements resulting from changes to the business and other uncertainties;
•restrictions on importing and exporting products;
•impacts related to late customer payments and contractual defaults associated with customer and supplier bankruptcies;
•potentially higher borrowing costs in the future;
•cybersecurity issues, as our network may become more vulnerable to cyberattacks due to increased remote access associated with work-from-home arrangements;
•our ability to use our net operating loss carryforwards may be limited;
•increased costs associated with possible facility closures to meet expected customer activity levels; and
•we may be required to record significant impairment charges with respect to assets, whose fair values may be negatively affected by the effects of the COVID-19 pandemic on our operations. Also, we may be required to write off obsolete inventory, and such charges may be significant.
The resumption of our normal business operations after the disruptions caused by the COVID-19 pandemic may be delayed or constrained by its lingering effects on the oil and gas industry. Any of the negative impacts of the COVID-19 pandemic, including those described above, alone or in combination with others, may have a significant
adverse effect on our financial condition, results of operations, or liquidity. The full extent to which the COVID-19 pandemic will negatively affect our financial condition, results of operations, or liquidity will depend on future developments that are highly uncertain and cannot be predicted, including the scope and duration of the pandemic, the COVID-19 infection rate, the efficacy of distribution of COVID-19 vaccines, the actions taken by authorities to contain it or treat its impact and the resulting impact on the oil and gas industry. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist, the full extent of the impact they will have on our financial condition, results of operations, or liquidity or the pace or extent of any subsequent recovery.
Current debt and equity market conditions may continue to limit our ability to obtain additional financing, including to pursue other business opportunities or refinancing existing indebtedness upon maturity.
Conditions in the market for debt and equity securities in the energy sector have increased the difficulty of obtaining debt or equity financing to grow our business. Due in part to the recent stock market decline, the closing price of our common stock was $0.86 as of December 31, 2020. As of March 3, 2021 the market price for our common stock was $2.59. At the current price for our common stock, acquisition and financing transactions that involve the use of our common equity may be significantly dilutive to our stockholders. The issuance of new convertible debt or equity securities in the future for acquisition and financing transactions, if available, could be significantly dilutive to our stockholders. We may have difficulty obtaining refinancing for our existing indebtedness upon maturity in the current market environment. TETRA’s term loan matures in 2025.
We encounter, and expect to continue to encounter, intense competition in the sale of our products and services.
We compete with numerous companies in each of our operating segments, many of which have substantially greater financial and other resources than we have. Certain of our competitors have lower standards of quality, and offer equipment and services at lower prices than we do. Other competitors have newer equipment that is better suited to our customers’ needs. Particularly during a period of low oil and natural gas pricing, to the extent competitors offer products or services at lower prices or higher quality, or more cost-effective products or services, our business could be materially and adversely affected. In addition, certain of our customers may elect to perform services internally in lieu of using our services, which could also materially and adversely affect our operations.
The profitability of our operations is dependent on other numerous factors beyond our control.
Our operating results in general, and gross profit in particular, are determined by market conditions and the products and services we sell in any period. Other factors, such as heightened competition, changes in sales and distribution channels, availability of skilled labor and contract services, shortages in raw materials, or inability to obtain supplies at reasonable prices, may also affect the cost of sales and the fluctuation of gross margin in future periods.
Other factors affecting our operating results and activity levels include oil and natural gas industry spending levels for exploration, completion, production, development, and acquisition activities, and impairments of long-lived assets. Customer consolidation may also lead to reductions in capital spending that could have a material adverse effect on our business. Low oil prices and the supply and demand imbalance are expected to adversely affect such levels of spending in the oil and natural gas industry. In particular, Completion Fluids & Products Division profitability in future periods will continue to be affected by the mix of its products and services, including the timing of TETRA CS Neptune completion fluid projects, which are also dependent upon the success of customer offshore exploration and drilling efforts. Our customers are maintaining reduced capital expenditure plans for 2021 in light of current market conditions. Such industry capital expenditure reductions have had, and are expected to continue to have, a negative effect on the demand for many of our products and services. This has had, and may continue to have, a negative effect on our revenues and results of operations. A large concentration of our operating activities is located in the Permian Basin region of Texas and New Mexico. Our revenues and profitability are particularly dependent upon oil and natural gas industry activity and spending levels in this region. Our operations may also be affected by technological advances, cost of capital, and tax policies. Adverse changes in any of these other factors may have a material adverse effect on our revenues and profitability.
We are a significant shareholder of CCLP and the value of our investment in CCLP, including future distributions received from CCLP, may fluctuate substantially.
On January 29, 2021, we entered into and closed the GP Sale with Spartan to sell the general partner of CCLP along with the IDRs and approximately 23.1% of the outstanding limited partner interests in CCLP. Following the closing of the GP Sale, we retained approximately 11.1% of the outstanding CCLP common units. The value of our investment in CCLP may be adversely affected by negative changes in its results of operations, cash flows and financial position, which may occur as a result of the many risks attendant with operating in the compression services industry.
CCLP has substantial indebtedness and interest expense, which in turn reduces its cash available to fund capital expenditures or for distribution to CCLP’s common unitholders, including us. CCLP’s ability to service its indebtedness will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors. If CCLP’s operating results are not sufficient to service its indebtedness, CCLP may be forced to consider taking actions such as reducing or delaying its business activities, investments and capital expenditures, delaying the increase of distributions, selling assets, restructuring or refinancing its indebtedness, or seeking additional equity capital or bankruptcy protection. Without the ability to increase CCLP’s compression equipment fleet or otherwise grow its operations, CCLP’s ability to continue to retain customers whose compression services needs are expanding and to increase distributions to its common unitholders, including us, in the future may be limited.
Changes in the economic environment have resulted, and could further result, in significant impairments of certain of our long-lived assets.
Under U.S. generally accepted accounting principles (“U.S. GAAP”), we review the carrying value of our long-lived assets when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, based on their expected future cash flows. The impact of reduced expected future cash flow could require the write-down of all or a portion of the carrying value for these assets, which would result in additional impairments, resulting in decreased earnings. During 2020, we recorded an impairment charge of $0.6 million primarily related to a right of use asset for the lease of our Canada office within our Water & Flowback Services Division as we ceased use of the office during the year. During the three year period ending December 31, 2020, we recorded a total of $95.5 million of impairments and other charges for long-lived assets other than goodwill. During the fourth quarter of 2019, we recorded an impairment of $91.6 million in our Completion Fluids & Products Division related to our El Dorado, Arkansas calcium chloride production plant facility assets as a result of a reduction in the cost of raw materials for certain of our other chemical production plants and reduced demand for calcium chloride from the El Dorado plant due to general market conditions in the oil and gas industry. During the fourth quarter of 2019, we also recorded an impairment of $0.3 million related to certain equipment assets in our Water & Flowback Services Division. During the third quarter of 2018, as a result of decreased expected future cash flows from a specific customer contract, we recorded a long-lived asset impairment of $2.9 million of an identified intangible asset within the Water & Flowback Services Division. Depressed commodity prices and/or adverse changes in the economic environment could result in a greater decrease in the demand for many of our products and services, which could impact the expected utilization rates of certain of our long-lived assets, including plant facilities, operating locations, and operating equipment.
As part of our internal annual business outlook for each of our reporting units that we performed during the fourth quarter of 2019, we considered changes in the global economic environment that negatively impacted our stock price and market capitalization. As part of the first step of goodwill impairment testing for our Water Management reporting unit (part of our Water & Flowback Services Division) as of December 31, 2019, the only reporting unit with goodwill, we determined that the fair value of the Water Management reporting unit was less than its carrying value, and the remaining balance of $25.9 million of goodwill was impaired.
We are dependent on third-party suppliers for specific products and equipment necessary to provide certain of our products and services.
We sell a variety of CBFs to the oil and gas industry and non-energy markets, including calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, sodium bromide, formate-based brines, and our TETRA CS Neptune fluids, some of which we manufacture and some of which are purchased from third parties. Sales of these products contribute significantly to our revenues. In our manufacture of calcium chloride, we use brines, hydrochloric acid, and other raw materials purchased from third parties. In our manufacture of brominated CBF products, we use elemental bromine, hydrobromic acid, and other raw materials that are purchased from third parties. Although we have long-term supply agreements with Lanxess, if we were unable to acquire these raw materials at reasonable
prices for a prolonged period, our Completion Fluids & Products Division business could be materially and adversely affected.
The fabrication of our production testing, well monitoring, sand separation, and water management equipment requires the purchase of various components, some of which we obtain from a single source or a limited group of suppliers. Our reliance on these suppliers exposes us to the risk of price increases, inferior component quality, or an inability to obtain an adequate supply of required components in a timely manner. The profitability or future growth of our Water & Flowback Services Division may be adversely affected due to our dependence on these key suppliers.
Operating and Technological Risks
We have technological and age-obsolescence risk, both with our products and services as well as with our equipment assets.
New drilling, completion, and production technologies and equipment are constantly evolving. If we are unable to adapt to new advances in technology or replace older assets with new assets, we are at risk of losing customers and market share. Certain equipment, such as a portion of our production testing equipment fleet, may be inadequate to meet the needs of our customers in certain markets. The permanent replacement or upgrade of any of our equipment will require significant capital. Due to the unique nature of many of these assets, finding a suitable or acceptable replacement may be difficult and/or cost prohibitive. The replacement or enhancement of these assets over the next several years may be necessary in order for us to effectively compete in the current marketplace.
Our operations involve significant operating risks and insurance coverage may not be available or cost-effective.
We are subject to operating hazards normally associated with the oilfield service industry, including automobile accidents, fires, explosions, blowouts, formation collapse, mechanical problems, abnormally pressured formations, and environmental accidents. Environmental accidents could include, but are not limited to oil and produced water spills, gas leaks or ruptures, uncontrollable flows of oil, gas, or well fluids, or discharges of CBFs or toxic gases or other pollutants. These operating hazards may also include injuries to employees and third parties during the performance of our operations.
We have maintained a policy of insuring our risks of operational hazards that we believe is customary in the industry. We believe that the limits of insurance coverage we have purchased are consistent with the exposures we face and the nature of our products and services. Due to economic conditions in the insurance industry, from time to time, we have increased our self-insured retentions for certain policies in order to minimize the increased costs of coverage, or we have reduced our limits of insurance coverage for, or not procured, certain coverage. In certain areas of our business, we, from time to time, have elected to assume the risk of loss for specific assets. To the extent we suffer losses or claims that are not covered, or are only partially covered by insurance, our results of operations could be adversely affected.
We are subject to a number of risks associated with the GP Sale, and these risks could adversely impact our operations, financial condition and business.
On January 29, 2021, we closed the sale of CCLP’s general partner and approximately 23.1% of the outstanding limited partner interests in CCLP to Spartan. We are subject to a number of risks associated with this transaction, including risks associated with:
•any required payments of indemnification obligations under the Purchase Agreement for retained liabilities and breaches of representations, warranties or covenants; and
•our failure to realize the full purchase price anticipated under the Purchase Agreement, including the ability of CCLP to generate adjusted EBITDA on or prior to December 31, 2022 sufficient to result in payment of the contingent consideration.
As a result of these risks, we may be unable to realize the anticipated benefits of the transaction, including the total amount of consideration we expect to realize. Our failure to realize the anticipated benefits of the transaction
would adversely impact our operations, financial condition and business and could limit our ability to pursue additional strategic transactions.
Weather-Related Risks
Certain of our operations are seasonal and depend, in part, on weather conditions.
In certain markets, the Water & Flowback Services Division’s onshore water management services can be dependent on adequate water supplies being available to its customers. To the extent severe drought or other weather-related conditions prevent our customers from obtaining needed water, frac water operations may not be possible and our Water & Flowback Services Division business may be negatively affected.
Severe weather, including named windstorms, and severe winter weather, can cause damage and disruption to our businesses.
A portion of our operations is susceptible to adverse weather conditions in the Gulf of Mexico, including hurricanes and other extreme weather conditions. Even if we do not experience direct damage from storms, we may experience disruptions in our operations, because we are unable to operate or our customers or suppliers may curtail their activities due to damage to their wells, platforms, pipelines, and facilities. From time to time, our onshore operations are also negatively affected by adverse weather conditions, including sustained rain and flooding. Severe weather during the winter may also have a significant impact on natural gas storage levels and reduce drilling activity and other customer activity substantially.
Financial Risks
The market price of our common stock has been and may continue to be volatile.
The market price of our common stock has fluctuated in the past and is subject to significant fluctuations in response to many factors, some of which are beyond our control, including the following:
•our operational performance;
•supply, demand, and prices of oil and natural gas;
•the activity levels of our customers;
•deviations in our earnings from publicly disclosed forward-looking guidance or analysts’ projections;
•recommendations by research analysts that cover us and other companies in our industry;
•risks related to acquisitions, divestitures and our growth strategy;
•uncertainty about current global economic conditions; and
•other general economic conditions.
During 2020, the closing price for our common stock ranged from a high of $2.03 per share to a low of $0.22 per share. In recent years, the stock market in general has experienced extreme price and volume fluctuations that have affected the market price for companies in industries similar to ours. Some of these fluctuations have been unrelated to operating performance and are attributable, in part, to outside factors such as the COVID-19 pandemic and its impact on the world economy. The volatility of our common stock may make it difficult to resell shares of our common stock at attractive prices.
Our long-term debt agreements contain covenants and other provisions that restrict our ability to take certain actions and may limit our ability to operate or grow our business in the future.
As of December 31, 2020, our total long-term debt outstanding of $199.9 million, excluding debt of CCLP included in liabilities of discontinued operations, consisted of the carrying amount outstanding under our credit agreement (the “Term Credit Agreement”) and our Asset-Based Credit Agreement (the “ABL Credit Agreement”), both of which we entered into in September 2018. Following the closing of the GP Sale on January 29, 2021, our consolidated balance sheet will no longer include the amounts of CCLP. We were required to use all net cash proceeds from the sale to repay borrowings under our Term Credit Agreement.
The ABL Credit Agreement and Term Credit Agreement each contain certain affirmative and negative covenants, including covenants that restrict the ability of TETRA and certain of its subsidiaries to take certain actions including, among other things and subject to certain significant exceptions, (i) incurring debt, (ii) granting
liens, (iii) engaging in mergers and other fundamental changes, (iv) making investments, (v) entering into, or amending, transactions with affiliates, (vi) paying dividends and making other restricted payments, (vii) prepaying other indebtedness, and (viii) selling assets. The ABL Credit Agreement also contains a provision that may require a fixed charge coverage ratio (as defined in the ABL Credit Agreement) of not less than 1.00 to 1.00 in the event that certain conditions associated with outstanding borrowings and cash availability occur. The Term Credit Agreement also contains a requirement that the borrowers comply at the end of each fiscal quarter with a minimum Interest Coverage Ratio (as defined in the Term Credit Agreement) of 1.00 to 1.00. Our Term Credit Agreement requires us to annually prepay up to 50% of Excess Cash Flow (as defined in the Term Credit Agreement) from the most recent full fiscal year. If our Leverage Ratio (as defined in the Term Credit Agreement) at year-end is less than 2.00 to 1.00 , the prepayment requirement is decreased to 25%. If our Leverage Ratio at year-end is less than 1.50 to 1.00, then no prepayment is required.
Our continuing ability to comply with covenants in our Long-Term Debt Agreements depends largely upon our ability to generate adequate earnings and operating cash flow.
We have continuing exposure to abandonment and decommissioning obligations associated with oil and gas properties previously owned by Maritech.
From 2001 to 2012, our former subsidiary, Maritech Resources, Inc. (“Maritech”), sold various oil and gas producing properties in numerous transactions to different buyers. In connection with those sales, the buyers generally assumed the decommissioning liabilities associated with the properties sold (the “Legacy Liabilities”) and generally became the successor operator. In some cases, Maritech retained certain liabilities and we provided guaranties of Maritech’s retained liabilities. Some buyers of these Maritech properties subsequently sold certain of these properties to other buyers, who also assumed the financial responsibilities associated with the properties’ operations, including decommissioning liabilities, and these buyers also typically became the successor operator of the properties. To the extent that a buyer of these properties fails to perform the decommissioning work required, a previous owner, including Maritech, may be required to perform operations to satisfy the decommissioning liabilities. As a result of the third-party indemnity agreements and corporate guaranties we have previously provided to the U.S. Department of the Interior and to other private third-parties as the former parent company of Maritech, we may be responsible for satisfying these decommissioning obligations if they are not satisfied by the current owners and operators of the properties or by Maritech. Significant decommissioning liabilities that were assumed by the buyers of the Maritech properties in these previous sales remain unperformed. If oil and natural gas pricing levels continue to be depressed or further deteriorate, one or more of these buyers may be unable to perform the decommissioning work required on a property previously owned by Maritech. If these buyers, or any successor owners of the Maritech properties, are unable to satisfy and extinguish their decommissioning liabilities due to bankruptcy or other liquidity issues, the U.S. Department of the Interior may seek to impose those decommissioning obligations on Maritech and on us due to our third party indemnity agreements, and contractual commitments and guaranties issued from time to time by us to the U.S. Department of the Interior and various third parties. The amount of cash necessary to satisfy these obligations could be significant and could adversely affect our business, results of operations, financial condition, and cash flows.
In March 2018, pursuant to a series of transactions, Maritech sold the remaining offshore leases held by Maritech to Orinoco Natural Resources, LLC (“Orinoco”) and, immediately thereafter, we sold all equity interest in Maritech to Orinoco. The assignments for six of the offshore leases conveyed to Orinoco have not been approved by the U.S. Department of the Interior and Maritech remains an owner of record for these leases. Maritech also remains a recognized operator of a portion of four other offshore properties. Under the Maritech Asset Purchase Agreement, Orinoco assumed all of Maritech’s decommissioning liabilities related to the leases conveyed to Orinoco (the “Orinoco Lease Liabilities”) and, under the Maritech Membership Interest Purchase Agreement, Orinoco assumed all other liabilities of Maritech, including the Legacy Liabilities, subject to limited exceptions unrelated to the decommissioning liabilities. Pursuant to a Bonding Agreement executed in connection with such purchase agreements, Orinoco provided non-revocable bonds in the aggregate amount of approximately $46.8 million to secure the performance of certain of Maritech’s decommissioning obligations related to the Orinoco Lease Liabilities and certain of Maritech’s remaining current decommissioning obligations (not including the Legacy Liabilities). Orinoco was required to replace the initial bonds delivered at closing with other non-revocable performance bonds in two stages. The first set of replacement bonds were required to be delivered within 90 days following closing and the second set of replacement bonds were required to be delivered within 180 days following closing. The replacement bonds had to meet certain additional requirements and were required to be in the aggregate sum of $47.0 million. In the event Orinoco did not provide the first or second set of replacement bonds, Orinoco was required to make cash escrow payments. Among the other requirements of the final replacement bonds was that
they must provide coverage for all of the asset retirement obligations of Maritech instead of only relating to specific properties. The payment obligations of Orinoco under the Bonding Agreement are guaranteed by Thomas M. Clarke and Ana M. Clarke pursuant to a separate guaranty agreement (the “Clarke Bonding Guaranty Agreement”). Orinoco has not delivered such replacement bonds and neither it nor the Clarkes has made any of the escrow payments required pursuant to the terms of the Bonding Agreement. We filed a lawsuit against Orinoco and the Clarkes to enforce the terms of the Bonding Agreement and the Clarke Bonding Guaranty Agreement. A summary judgment was initially granted in favor of Orinoco and the Clarkes, which dismissed our claims against Orinoco under the Bonding Agreement and against the Clarkes under the Clarke Bonding Guaranty Agreement. We filed an appeal and also asked the trial court to grant a new trial on the summary judgment to modify the judgment because we believe this judgment should not have been granted. On November 5, 2019, the trial court signed an order granting our motion for new trial and vacating the prior order granting summary judgment for Orinoco and the Clarkes. The parties are awaiting direction from the court on a new scheduling order and/or trial setting. The non-revocable performance bonds delivered at the closing remain in effect.
If in the future we become liable for decommissioning liabilities associated with any property covered by either an initial bond or stage 1 permanent bond, the Bonding Agreement provides that if we call any of the initial bonds or the stage 1 permanent bonds to satisfy such liability and the amount of the bond payment is not sufficient to pay for such liability, Orinoco will pay us for the additional amount required. To the extent Orinoco is unable to cover any such deficiency or we become liable for a significant portion of the Legacy Liabilities, our financial condition and results of operations may be negatively affected.
Possible changes in the U.S. Department of Interior’s supplemental bonding and financial assurance requirements may increase our risks associated with the decommissioning obligations pertaining to oil and gas properties previously owned by Maritech.
Recent and additional anticipated changes to the supplemental bonding and financial assurance program managed by the U.S. Department of the Interior could require all oil and gas owners and operators with infrastructure in the Gulf of Mexico to provide additional supplemental bonds or other acceptable financial assurance for decommissioning liabilities. These changes have the potential to adversely impact the financial condition of lease owners and operators in the Gulf of Mexico and increase the number of such owners and operators seeking bankruptcy protection, given current oil and gas prices. In July 2016, the U.S. Department of the Interior issued a Notice to Lessees and Operators (“2016 NTL”) that strengthened requirements for the posting of additional financial assurance by offshore lease owners and operators to assure that sufficient security is available to satisfy and extinguish decommissioning obligations with respect to offshore wells, platforms, pipelines and other facilities. The 2016 NTL, which became effective in September 2016, eliminated the past practice of waiving supplemental bonding requirements where lease owners or operators, or their guarantors, could demonstrate a certain level of financial strength. Instead, under the 2016 NTL, the U.S. Department of the Interior indicated that it would allow lease owners and operators to “self-insure,” but only up to 10% of their “tangible net worth,” which is defined as the difference between a company’s total assets and the value of all liabilities and intangible assets. It is unclear how this self-insurance allowance relates to lease owners or operators with a guarantor presently in place.
Although the U.S. Department of the Interior under the Trump Administration ultimately rescinded the 2016 NTL in 2020, the Biden Administration could seek to reconsider the changes made by the U.S. Department of the Interior under the Trump Administration and, should the Biden Administration re-issue and fully implement guidance or rules analogous to, or more rigorous than, the 2016 NTL, such developments could increase operating costs for lease owners and operators in the Gulf of Mexico and reduce the availability of surety bonds due to the increased demands for such bonds in a low-price commodity environment. As a result, there is significant uncertainty surrounding financial assurance obligations for Gulf of Mexico lease owners and operators and for us through the third party indemnity agreements we have provided for Maritech liabilities to the U.S. Department of the Interior and/or to third parties through our private guarantees.
The U.S. Department of the Interior also recently increased its estimates for decommissioning liabilities in the Gulf of Mexico, causing the potential need for additional supplemental bonding and/or other financial assurances to be dramatically increased. When coupled with the volatile and currently low prices of oil and gas, it is difficult to predict the impact of the rule and regulatory changes already promulgated and as may be forthcoming by the U.S. Department of the Interior relating to financial assurance for decommissioning liabilities. Any revisions to the U.S. Department of the Interior’s supplemental bonding process could result in demands for the posting of increased financial assurances by owners and operators in the Gulf of Mexico, including Maritech, Orinoco and the other entities to whom Maritech divested its Gulf of Mexico assets, but such demands cannot be directly placed on
us due to the fact that we are only a former parent company of Maritech and are only a guarantor as opposed to an actual lease owner or operator. This may force lease owners and operators of leases and other infrastructure in the Gulf of Mexico to obtain surety bonds or other forms of financial assurance, the costs of which could be significant. Moreover, anticipated changes to the bonding and financial assurance program for the Gulf of Mexico could result in the loss of supplemental bonding waivers for a large number of lease owners and operators of infrastructure in the Gulf of Mexico, which could in turn force these owners and operators to seek additional surety bonds which could exceed the surety bond market’s ability to provide such additional financial assurance. Lease owners and operators who have already leveraged their assets could face difficulty obtaining surety bonds because of concerns the surety may have about the priority of their liens on their collateral as well as the creditworthiness of such lease owners and operators. Consequently, anticipated changes to the bonding and financial assurance program could result in additional lease owners and operators in the Gulf of Mexico initiating bankruptcy proceedings, which in turn could result in the U.S. Department of the Interior seeking to impose decommissioning costs on predecessors in interest and providers of third party indemnity agreements in the event that the current lease owners and/or operators cannot meet their decommissioning obligations. As a result, this could increase the risk that we may be required to step in and satisfy remaining decommissioning liabilities of Maritech and any buyer of the Maritech properties, including Orinoco, through our third party indemnity agreements and private guarantees, which obligations could be significant and could adversely affect our business, results of operations, financial condition and cash flows.
We are exposed to significant credit risks.
We face credit risk associated with the significant amounts of accounts receivable we have with our customers in the energy industry. Many of our customers, particularly those associated with our onshore operations, are small- to medium-sized oil and gas operators that may be more susceptible to declines in oil and gas commodity prices or generally increased operating expenses than larger companies. Our ability to collect from our customers is impacted by the current volatile oil and natural gas price environment and we may face increased credit risks if the current reduced price of oil continues for an extended period of time.
As discussed in the preceding risk factors, we face the risk of having to satisfy decommissioning liabilities on properties presently or formerly owned by Maritech. Continued decreased oil and natural gas prices have resulted in reduced revenues and cash flows for oil and gas lease owners and operators, including companies that have purchased Maritech properties or are joint-owners in properties presently and formerly owned by Maritech and from whom Maritech is entitled to receive payments upon satisfaction of certain decommissioning obligations. Consequently, we face credit risk associated with the ability of these companies to satisfy their decommissioning liabilities. If these companies are unable to satisfy their obligations, it will increase the possibility that we will become liable for such decommissioning obligations in the future.
Our operating results and cash flows for certain of our subsidiaries are subject to foreign currency risk.
The operations of certain of our subsidiaries are exposed to fluctuations between the U.S. dollar and certain foreign currencies, particularly the euro, the British pound, the Mexican peso, and the Argentinian peso. Our plans to grow our international operations could cause this exposure from fluctuating currencies to increase. Historically, exchange rates of foreign currencies have fluctuated significantly compared to the U.S. dollar, and this exchange rate volatility is expected to continue. Significant fluctuations in foreign currencies against the U.S. dollar could adversely affect our balance sheet and results of operations.
We are exposed to interest rate risks with regard to our credit facility debt and future refinancing thereof.
As of December 31, 2020, we had no outstanding balance under our ABL Credit Agreement and $213.5 million outstanding under our Term Credit Agreement. Following repayment from GP Sale proceeds, the balance outstanding under our Term Credit Agreement is $201.7 million. These credit facilities consist of floating rate loans that bear interest at an agreed upon percentage rate spread above London Interbank Offered Rate (“LIBOR”) or an alternate base rate. Accordingly, whenever we have amounts outstanding under these facilities, our cash flows and results of operations will be subject to interest rate risk exposure associated with the debt balance outstanding. We currently are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.
Our ABL Credit Agreement is scheduled to mature on September 10, 2023. Our Term Loan Agreement is scheduled to mature on September 10, 2025. There can be no assurance that financial market conditions or borrowing terms at the times these existing debt agreements are renegotiated will be as favorable as the current
terms and interest rates. We may be unable to obtain financing in the future for working capital, capital expenditures, acquisitions, debt service requirements, or other purposes.
Legal, Regulatory, and Political Risks
Our operations are subject to extensive and evolving U.S. and foreign federal, state and local laws and regulatory requirements that increase our operating costs and expose us to potential fines, penalties, and litigation.
Laws and regulations govern our operations, including those relating to corporate governance, employees, taxation, fees, importation and exportation restrictions, environmental affairs, health and safety, and the manufacture, storage, handling, transportation, use, and sale of chemical products. Certain foreign countries impose additional restrictions on our activities, such as currency restrictions and restrictions on various labor practices. These laws and regulations are becoming increasingly complex and stringent, and compliance is becoming increasingly expensive. Governmental authorities have the power to enforce compliance with these regulations, and violators are subject to civil and criminal penalties, including civil fines, and injunctions. Third parties may also have the right to pursue legal actions to enforce compliance with certain laws and regulations. It is possible that increasingly strict environmental, health and safety laws, regulations, and enforcement policies could result in substantial costs and liabilities to us.
For example, the EPA has asserted federal regulatory authority under the Safe Drinking Water Act Underground Injection Control program over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance for such activities, and issued a final regulation under the Clean Water Act prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and gas facilities. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Certain environmental and other groups have suggested that additional federal, state, and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. Several states have adopted regulations that require operators to disclose the chemical constituents in hydraulic fracturing fluids. We cannot predict whether any federal, state or local laws or regulations will be enacted regarding hydraulic fracturing, and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on oil and gas operators through the adoption of new laws and regulations, the domestic demand for certain of our products and services could be decreased or subject to delays.
We operate in the U.S. Gulf of Mexico. At this time, we cannot predict the full impact that other regulatory actions that may be mandated by the federal government may have on our operations or the operations of our customers. Other governmental or regulatory actions could further reduce our revenues and increase our operating costs, including the cost to insure offshore operations, resulting in reduced cash flows and profitability.
Our onshore and offshore operations expose us to risks such as the potential for harmful substances escaping into the environment and causing damages or injuries, which could be substantial. We maintain limited environmental liability insurance covering named locations and environmental risks associated with contract services for oil and gas operations. We could be materially and adversely affected by an enforcement proceeding or a claim that is not covered or is only partially covered by insurance.
Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties, or international agreements that impose additional restrictions on the industry may adversely affect our financial results. Regulators are becoming more focused on air emissions from oil and gas operations, including volatile organic compounds, hazardous air pollutants, and greenhouse gases (“GHGs”). In particular, the focus on GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our financial results if such laws, regulations, treaties, or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties, or international agreements could result in increased compliance costs, capital spending requirements, or additional operating restrictions for us, which may have a negative impact on our financial results.
In addition to increasing our risk of environmental liability, the rigorous enforcement of environmental laws and regulations has accelerated demand for our products and services in some of the markets we serve.
Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas our customers produce, while the physical effects of climate change could disrupt production and cause us to incur costs in preparing for or responding to those effects.
The EPA has adopted various regulations to restrict emissions of GHGs under existing provisions of the CAA. Such EPA rules regulate GHG emissions under the CAA and require a reduction in emissions of GHGs from motor vehicles and from certain large stationary sources. For example, the EPA published final rules in June 2016 that require the reduction of volatile organic compounds and methane emissions from certain hydraulically fractured natural gas wells and further require that most wells use so-called “green” completions. These regulations also established new requirements regarding emissions from production-related wet seal and reciprocating compressors, pneumatic controllers and storage vessels. While the EPA under the Trump Administration finalized rules to rescind or modify certain of these requirements in September 2020, including rescission of the methane-specific requirements applicable to sources in the production and processing segments of the oil and gas industry, various states and industry and environmental groups are separately challenging the EPA’s 2016 standards and its September 2020 final rule. Moreover, notwithstanding the current court challenges, the EPA under the Biden Administration is expected to reconsider the September 2020 final rule, which could result in more stringent methane emission rulemaking. In addition, the EPA also requires the annual reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, as well as from certain oil and gas production facilities.
In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions (the “Paris Agreement”). The Paris Agreement entered into force in November 2016 after more than 170 nations ratified or otherwise indicated their intent to be bound by the Paris Agreement. Although the United States withdrew from the Paris Agreement in November 2020, President Biden issued an executive order recommitting the United States to the Paris Agreement in January 2021.
President Biden has also issued executive orders that commit to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and an increased emphasis on climate-related risk across government agencies and economic sectors. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our facilities and operations could require us to incur costs. The U.S. Congress (“Congress”) has considered and almost one-half of the states have adopted legislation that seeks to control or reduce emissions of GHGs from a wide range of sources. Any such legislation could adversely affect demand for the oil and natural gas our customers produce and, in turn, demand for our products and services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations and cause us to incur costs in preparing for or responding to those effects.
Our operations in foreign countries exposes us to complex regulations and may present us with new obstacles to growth.
We plan to continue to grow both in the United States and in foreign countries. We have established operations in Argentina, Brazil, Finland, Ghana, Mexico, Norway, Saudi Arabia, Sweden, and the United Kingdom, as well as other foreign countries. Foreign operations carry special risks. Our business in the countries in which we currently operate and those in which we may operate in the future could be limited or disrupted by:
•restrictions on repatriating cash back to the United States;
•the impact of compliance with anti-corruption laws on our operations and competitive position in affected countries and the risk that actions taken by us or our agents may violate those laws;
•government controls and government actions, such as expropriation of assets and changes in legal and regulatory environments;
•import and export license requirements;
•political, social, or economic instability;
•trade restrictions;
•changes in tariffs and taxes; and
•our limited knowledge of these markets or our inability to protect our interests.
We and our affiliates operate in countries where governmental corruption has been known to exist. While we and our subsidiaries are committed to conducting business in a legal and ethical manner, there is a risk of violating the U.S. Foreign Corrupt Practices Act, the U.K Bribery Act, or laws or legislation promulgated pursuant to the 1997 OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions or other applicable anti-corruption regulations that generally prohibit the making of improper payments to foreign officials for the purpose of obtaining or keeping business. Violation of these laws could result in monetary penalties against us or our subsidiaries and could damage our reputation and our ability to do business.
Foreign governments and agencies often establish permit and regulatory standards different from those in the U.S. If we cannot obtain foreign regulatory approvals, or if we cannot obtain them in a timely manner, our growth and profitability from foreign operations could be adversely affected.
Regulatory initiatives related to hydraulic fracturing in the countries where we and our customers operate could result in operating restrictions or delays in the completion of oil and gas wells that may reduce demand for our services.
Although we do not directly engage in hydraulic fracturing, our operations support many of our exploration and production customers in such activities. The practice continues to be controversial in certain parts of the country, resulting in increased scrutiny and regulation of the hydraulic fracturing process, including by federal and state agencies and local municipalities.
Hydraulic fracturing typically is regulated by state oil and gas commissions or similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process in the U.S. For example, the EPA (i) asserted regulatory authority pursuant to the federal Safe Drinking Water Act Underground Injection Control program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities, (ii) published final rules under the federal CAA in 2012 and published additional final regulations in June 2016 governing methane and volatile organic compound performance standards, including standards for the capture of air emissions released by the oil and natural gas hydraulic fracturing industry (however, rules were finalized in September 2020 modifying or rescinding some of these requirements), (iii) in June 2016 published an effluent limitations final rule prohibiting the discharge of waste water from shale natural-gas extraction operations to a treatment plant, and (iv) in 2014 published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. In 2016, the U.S. Bureau of Land Management (“BLM”) published a final rule that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. BLM under the Trump Administration issued a final rule in late 2018 rescinding the 2016 action; however, a California federal court vacated the 2018 final rule in July 2020, and a Wyoming federal court subsequently vacated the 2016 final rule in October 2020. Accordingly, the 2016 final rule is no longer in effect, but the Wyoming decision is expected to be appealed. Moreover, the Biden Administration is expected to pursue regulatory initiatives that restrict hydraulic fracturing activities on federal lands as well as other actions to more stringently regulate certain aspects of oil and gas development such as air emissions and water discharges. On January 20, 2021, the Acting Secretary of the U.S. Department of the Interior issued an order, effective immediately, that suspends new oil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days. In addition, President Biden issued an executive order on January 27, 2021, that suspends new leasing activities for oil and gas exploration and production on non-Indian federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities on such lands and waters. However, these orders do not apply to operations under existing leases and permits.
The Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Texas, Oklahoma and New Mexico, have adopted, and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted, our customers could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our customers in the production of oil and gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of additional regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and an associated decrease in demand for our services and increased compliance costs and time, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
Our proprietary rights may be violated or compromised, which could damage our operations.
We own numerous patents, patent applications, and unpatented trade secret technologies in the U.S. and certain foreign countries. There can be no assurance that the steps we have taken to protect our proprietary rights will be adequate to deter misappropriation of these rights. In addition, independent third parties may develop competitive or superior technologies.
Our operations and reputation may be impaired if our information technology systems fail to perform adequately or if we are the subject of a data breach or cyberattack.
Our information technology systems are critically important to operating our business efficiently. We rely on our information technology systems to manage our business data, communications, supply chain, customer invoicing, employee information, and other business processes. We outsource certain business process functions to third-party providers and similarly rely on these third parties to maintain and store confidential information on their systems. The failure of these information technology systems to perform as we anticipate could disrupt our business and could result in transaction errors, processing inefficiencies, and the loss of sales and customers, causing our business and results of operations to suffer.
Although we allocate significant resources to protect our information technology systems, we have experienced varying degrees of cyber-incidents in the normal conduct of our business, including viruses, worms, other destructive software, process breakdowns, phishing and other malicious activities. On January 6, 2020, the Department of Homeland Security issued a public warning that indicated companies in the energy industry might be specific targets of cybersecurity threats. Such breaches have in the past and could again in the future result in unauthorized access to information including customer, supplier, employee, or other company confidential data. We do carry insurance against these risks, although the potential damages we might incur could exceed our available insurance coverage. We also invest in security technology, perform penetration tests from time to time, and design our business processes to attempt to mitigate the risk of such breaches. However, there can be no assurance that security breaches will not occur. Moreover, the development and maintenance of these measures requires continuous monitoring as technologies change and efforts to overcome security measures evolve. We have experienced and expect to continue to experience, cyber security threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
Our properties consist primarily of our corporate headquarters facility, chemical plants, processing plants and distribution facilities. The following information describes facilities that we leased or owned as of December 31, 2020. We believe our facilities are adequate for our present needs.
Facilities
Completion Fluids & Products Division
Our Completion Fluids & Products Division facilities include six operating chemical production plants located in the states of Arkansas, California, Louisiana, and West Virginia, and the country of Finland, having a total production capacity of more than 1.1 million equivalent liquid tons per year. The two California locations consist of 29 square miles of leased mineral acreage and solar evaporation ponds, and related owned production and storage facilities.
As an inducement to locate our El Dorado calcium chloride production plant in Union County, Arkansas, we received certain ad valorem property tax incentives. Our facility is located just outside the city of El Dorado, Arkansas, on property that is leased from Union County, Arkansas. We have the option of purchasing the property at any time during the term of the lease for a nominal price. The term of the lease expires in 2035, at which time we also have the option to purchase the property at a nominal price. Under the terms of the lease, we are responsible for all costs incurred related to the facility. In April 2020, in response to market conditions, we began the process of discontinuing chemical production operations at this facility. We continued to manufacture and deliver products through early June 2020, at which time we began a sequenced shutdown of the manufacturing facility. As of December 31, 2020, the plant is not operational.
In addition to the production facilities described above, the Completion Fluids & Products Division owns or leases multiple service center facilities in the United States and in other countries. The Completion Fluids & Products Division also leases several offices and numerous terminal locations in the U.S. and in other countries.
We lease over 27,000 acres of brine leases in Magnolia, Arkansas, which contain bromine and lithium. This acreage is leased for possible future development and as a source of supply for our bromine and other raw materials.
Water & Flowback Services Division
The Water & Flowback Services Division conducts its operations through production testing service centers (most of which are leased) in the U.S., located in Arkansas, Colorado, Louisiana, New Mexico, North Dakota, Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming. In addition, the Water & Flowback Services Division has leased facilities in Mexico and certain countries in Europe, the Middle East and South America.
Corporate
Our headquarters is located in The Woodlands, Texas, in a 153,000 square foot office building, which is located on 2.6 acres of land, under a lease that expires in 2027. In addition, we own a 28,000 square foot technical facility in The Woodlands, Texas, to service our Completion Fluids & Products and Water & Flowback Services Divisions’ operations.
Item 3. Legal Proceedings.
We are named defendants in numerous lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not consider it reasonably possible that a loss resulting from such lawsuits or other proceedings in excess of any amounts accrued has been incurred that is expected to have a material adverse effect on our financial condition, results of operations or liquidity. See Note 12 - “Commitments and Contingencies” in the Notes to Consolidated Financial Statements for further information.
Item 4. Mine Safety Disclosures.
None.
Notes to Consolidated Financial Statements
December 31, 2020
NOTE 1 — ORGANIZATION AND OPERATIONS
We are a geographically diversified oil and gas services company, focused on completion fluids and associated products and services, comprehensive water management, frac flowback and production well testing. We were incorporated in Delaware in 1981. Our products and services are delivered through two reporting segments – Completion Fluids & Products and Water & Flowback Services. Unless the context requires otherwise, when we refer to “we,” “us,” and “our,” we are describing TETRA Technologies, Inc. and its consolidated subsidiaries on a consolidated basis.
Our Completion Fluids & Products Division manufactures and markets clear brine fluids, additives, and associated products and services to the oil and gas industry for use in well drilling, completion, and workover operations in the United States and in certain countries in Latin America, Europe, Asia, the Middle East and Africa. The Division also markets liquid and dry calcium chloride products manufactured at its production facilities or purchased from third-party suppliers to a variety of markets outside the energy industry.
Our Water & Flowback Services Division provides onshore oil and gas operators with comprehensive water management services. The Division also provides frac flowback, production well testing, offshore rig cooling, and other associated services in many of the major oil and gas producing regions in the United States and Mexico, as well as in oil and gas basins in certain countries in Latin America, Europe, and the Middle East.
NOTE 2 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
Our consolidated financial statements include the accounts of our wholly owned subsidiaries. We consolidated the financial statements of our former CSI Compressco LP subsidiary (“CCLP”), as we determined that CCLP was a variable interest entity and we were the primary beneficiary as of December 31, 2020. As of December 31, 2020, we controlled the financial interests of CCLP and had the ability to direct the activities of CCLP that most significantly impacted its economic performance through our ownership of its general partner. As of December 31, 2020, our cash flows from our investment in CCLP were limited to the quarterly distributions we received on our CCLP common units and general partner interest (including incentive distribution rights (“IDRs”)) and the amounts collected for services we performed on behalf of CCLP. TETRA’s capital structure and CCLP’s capital structure are separate, and do not include cross default provisions, cross collateralization provisions or cross guarantees. All intercompany accounts and transactions have been eliminated in consolidation.
Substantially all of our former Compression Division’s operations were conducted through our partially-owned CCLP subsidiary. On January 29, 2021, we entered into the Purchase and Sale Agreement with Spartan Energy Partners LP and Spartan Energy Holdco, LLC (together, “Spartan”) pursuant to which we sold the general partner of CCLP, including the IDRs in CCLP and approximately 23.1% of the outstanding limited partner interests in CCLP, in exchange for a combination of $13.4 million in cash paid at closing, $0.5 million in cash payable on the six-month anniversary of the closing and $3.1 million in contingent consideration in the form of cash and/or CCLP common units if CCLP achieves certain financial targets on or before December 31, 2022. Following the closing of the transaction, we retained approximately 11.1% of the outstanding CCLP common units. Throughout this Annual Report, we refer to the transaction with Spartan as the “GP Sale.” We have reflected the operations of our former Compression Division as discontinued operations for all periods presented. See Note 3 - “Discontinued Operations” and Note 18 - “Subsequent Event.” for further information.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclose contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues, expenses and impairments during the reporting period. Actual results could differ from those estimates, and such differences could be material.
Reclassifications
Certain previously reported financial information has been reclassified to conform to the current year’s presentation. For a discussion of the reclassification of the financial presentation of our former Compression Division as discontinued operations, see Note 3 - “Discontinued Operations”. Unless otherwise noted, amounts and disclosures throughout these Notes to Consolidated Financial Statements relate solely to continuing operations and exclude all discontinued operations.
Cash Equivalents
We consider all highly liquid cash investments with a maturity of three months or less when purchased to be cash equivalents.
Financial Instruments
Financial instruments that subject us to concentrations of credit risk consist principally of trade receivables with companies in the energy industry. Our policy is to evaluate, prior to providing goods or services, each customer’s financial condition and to determine the amount of open credit to be extended. We generally require appropriate, additional collateral as security for credit amounts in excess of approved limits. Our customers consist primarily of major, well-established oil and gas producers and independent oil and gas companies. Payment terms are on a short-term basis.
We have currency exchange rate risk exposure related to transactions denominated in a foreign currency as well as to investments in certain of our international operations. Our risk management activities include the use of foreign currency forward purchase and sale derivative contracts as part of a program designed to mitigate the currency exchange rate risk exposure on selected international operations.
We have no outstanding balance under our variable rate revolving credit facilities as of December 31, 2020. Outstanding balances on variable rate bank credit facilities create market risk exposure related to changes in applicable interest rates.
Allowance for Doubtful Accounts
The allowance for doubtful accounts is determined on a specific identification basis when we believe that the collection of specific amounts owed to us is not probable. Changes in the allowance are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
(In Thousands)
|
|
At beginning of period
|
|
$
|
1,912
|
|
|
$
|
1,354
|
|
|
$
|
368
|
|
|
Activity in the period:
|
|
|
|
|
|
|
|
Provision for doubtful accounts
|
|
5,672
|
|
|
2,580
|
|
|
1,152
|
|
|
Account (chargeoffs) recoveries
|
|
(760)
|
|
|
(2,022)
|
|
|
(166)
|
|
|
|
|
|
|
|
|
|
|
At end of period
|
|
$
|
6,824
|
|
|
$
|
1,912
|
|
|
$
|
1,354
|
|
Inventories
Inventories are stated at the lower of cost or net realizable value. Except for work in progress inventory, cost is determined using the weighted average method. The cost of work in progress is determined using the specific identification method.
Property, Plant, and Equipment
Property, plant, and equipment are stated at cost. Expenditures that increase the useful lives of assets are capitalized. The cost of repairs and maintenance is charged to operations as incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets, which are generally as follows:
|
|
|
|
|
|
|
|
|
|
|
Buildings
|
|
15 – 40 years
|
|
Machinery and equipment
|
|
2 – 20 years
|
|
Automobiles and trucks
|
|
3 – 4 years
|
|
Chemical plants
|
|
15 – 30 years
|
|
|
|
|
Leasehold improvements are depreciated over the shorter of the remaining term of the associated lease or its useful life. Depreciation expense, excluding impairments and other charges, for the years ended December 31, 2020, 2019, and 2018 was $32.4 million, $42.9 million and $39.4 million, respectively.
Construction in progress as of December 31, 2020 and 2019 consisted primarily of equipment fabrication projects.
Intangible Assets other than Goodwill
Patents, trademarks, and other intangible assets are amortized on a straight-line basis over their estimated useful lives, ranging from 1 to 13 years. Amortization expense of patents, trademarks, and other intangible assets was $5.3 million, $5.1 million, and $4.3 million for the years ended December 31, 2020, 2019, and 2018, respectively, and is included in depreciation, amortization and accretion. The estimated future annual amortization expense of patents, trademarks, and other intangible assets is $4.5 million for 2021, $4.1 million for 2022, $3.8 million for 2023, $3.7 million for 2024, and $3.7 million for 2025.
Intangible assets other than goodwill are tested for recoverability whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. In such an event, we will determine the fair value of the asset using an undiscounted cash flow analysis of the asset at the lowest level for which identifiable cash flows exist. If an impairment has occurred, we will recognize a loss for the difference between the carrying value and the estimated fair value of the intangible asset. During 2018, certain intangible assets were impaired. See “Impairments of Long-Lived Assets” section in Note 6 - “Impairments and Other Charges”.
Goodwill
Goodwill represents the excess of cost over the fair value of the net assets acquired in business combinations. We perform a goodwill impairment test at a reporting unit level on an annual basis or whenever indicators of impairment are present. We perform the annual test of goodwill impairment as of the last day of the fourth quarter of each year. The first step of the impairment test is to compare the estimated fair value of the reporting unit to its recorded net book value (including goodwill). If the estimated fair value is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the carrying amount of the reporting unit exceeds its estimated fair value, an impairment loss is calculated based on the difference between the fair value and carrying value. These estimates are imprecise and are subject to our estimates of the future cash flows of the reporting unit. These estimates and judgments are affected by numerous factors, including the general economic environment at the time of our assessment. During the fourth quarter of 2019, we recorded an impairment on all our remaining goodwill. See Note 5 - “Goodwill” for additional discussion.
Leases
As a lessee, unless the lease meets the criteria of short-term and is excluded per our policy election described below, we initially recognize a lease liability and related right-of-use asset on the commencement date. The right-of-use asset represents our right to use an underlying asset and the lease liability represents our obligation to make lease payments to the lessor over the lease term.
Long-term operating leases are included in operating lease right-of-use assets, accrued liabilities and other, and operating lease liabilities in our consolidated balance sheet as of December 31, 2020. Long-term finance leases are not material. We determine whether a contract is or contains a lease at inception of the contract. Where we are a lessee in a contract that includes an option to extend or terminate the lease, we include the extension period or exclude the period covered by the termination option in our lease term in determining the right-of-use asset and lease liability, if it is reasonably certain that we would exercise the option.
As an accounting policy election, we do not include short-term leases on our balance sheet. Short-term leases include leases with a term of 12 months or less, inclusive of renewal options we are reasonably certain to exercise. The lease payments for short-term leases are included as operating lease costs on a straight-line basis over the lease term in cost of revenues or general and administrative expense based on the use of the underlying asset. We recognize lease costs for variable lease payments not included in the determination of a lease liability in the period in which an obligation is incurred.
As allowed by U.S. GAAP, CCLP does not separate nonlease components from the associated lease component for its compression services contracts and instead accounts for those components as a single component based on the accounting treatment of the predominant component. In the evaluation of whether Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 842 “Leases” or ASC 606 “Revenue from Contracts with Customers” is applicable to the combined component based on the predominant component, CCLP determined the services nonlease component is predominant, resulting in the ongoing recognition of compression services contracts following ASC 606.
Our operating and finance leases are recognized at the present value of lease payments over the lease term. When the implicit discount rate is not readily determinable, we use our incremental borrowing rate to calculate the discount rate used to determine the present value of lease payments. Consistent with other long-lived assets or asset groups that are held and used, we test for impairment of our right-of-use assets when impairment indicators are present.
Impairments of Long-Lived Assets
Impairments of long-lived assets, including identified intangible assets, are determined periodically when indicators of impairment are present. If such indicators are present, the determination of the amount of impairment is based on our judgments as to the future undiscounted operating cash flows to be generated from these assets throughout their remaining estimated useful lives. If these undiscounted cash flows are less than the carrying amount of the related asset, an impairment is recognized for the excess of the carrying value over its fair value. Assets held for disposal are recorded at the lower of carrying value or estimated fair value less estimated selling costs. See Note 6 - “Impairments and Other Charges” for additional discussion of recorded impairments.
Asset Retirement Obligations
We operate facilities in various U.S. and foreign locations that are used in the manufacture, storage, and sale of our products, inventories, and equipment. These facilities are a combination of owned and leased assets. We are required to take certain actions in connection with the retirement of these assets. Asset retirement obligations are recorded in accordance with ASC 410, “Asset Retirement and Environmental Obligations,” whereby the estimated fair value of a liability for asset retirement obligations is recognized in the period in which it is incurred and in which a reasonable estimate can be made. Such estimates are based on relevant assumptions that we believe are reasonable. We have reviewed our obligations in this regard in detail and estimated the cost of these actions. The associated asset retirement costs are capitalized as part of the carrying amount of these long-lived assets and are depreciated on a straight-line basis over the life of the assets.
Environmental Liabilities
Environmental expenditures that result in additions to property and equipment are capitalized, while other environmental expenditures are expensed. Environmental remediation liabilities are recorded on an undiscounted basis when environmental assessments or cleanups are probable and the costs can be reasonably estimated. We have no significant environmental remediation liabilities as of December 31, 2020 and 2019. Estimates of future environmental remediation expenditures often consist of a range of possible expenditure amounts, a portion of which may be in excess of amounts of liabilities recorded. In such an instance, we disclose the full range of amounts reasonably possible of being incurred. Any changes or developments in environmental remediation efforts are accounted for and disclosed each quarter as they occur. Any recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
Complexities involving environmental remediation efforts can cause estimates of the associated liability to be imprecise. Factors that cause uncertainties regarding the estimation of future expenditures include, but are not limited to, the effectiveness of the anticipated work plans in achieving targeted results and changes in the desired remediation methods and outcomes as prescribed by regulatory agencies. Uncertainties associated with environmental remediation contingencies are pervasive and often result in wide ranges of reasonably possible outcomes. Estimates developed in the early stages of remediation can vary significantly. Normally, a finite estimate of cost does not become fixed and determinable at a specific point in time. Rather, the costs associated with environmental remediation become estimable as the work is performed and the range of ultimate cost becomes more defined. It is possible that cash flows and results of operations could be materially affected by the impact of the ultimate resolution of these contingencies.
Revenue Recognition
Performance Obligations. Revenue is generally recognized when we transfer control of our products or services to our customers. Revenue is measured as the amount of consideration we expect to receive in exchange for transferring products or providing services to our customers. We receive cash equal to the invoice price for most sales of product and services and payment terms typically range from 30 to 60 days from the date we invoice our customer. Since the period between when we deliver products or services and when the customer pays for such products or services is not expected to exceed one year, we have elected not to calculate or disclose a financing component for our customer contracts.
Depending on the terms of the arrangement, we may also defer the recognition of revenue for a portion of the consideration received because we have to satisfy a future performance obligation.
For any arrangements with multiple performance obligations, we use management’s estimated selling price to determine the stand-alone selling price for separate performance obligations. For revenue associated with mobilization of service equipment as part of a service contract arrangement, such revenue, if significant, is deferred and amortized over the estimated service period.
Product Sales. Product sales revenues are recognized at a point in time when we transfer control of our product offerings to our customers, generally when we ship products from our facility to our customer. The product sales for our Completion Fluids & Products Division consist primarily of clear brine fluids (“CBFs”), additives, and associated manufactured products. Product sales for our Water & Flowback Services Division are typically attributed to specific performance obligations within certain production testing service arrangements.
Services. Service revenues represent revenue recognized over time, as our customer arrangements typically provide agreed upon day-rates and we recognize service revenue based upon the number of days services have been performed. Service revenue recognized over time is associated with a majority of our Water & Flowback Services Division arrangements, and a small portion of Completion Fluids & Products Division revenue that is associated with completion fluid service arrangements. Our customer contracts are generally for terms of one year or less. The majority of the service arrangements in the Water & Flowback Services Division are for a period of 90 days or less.
Sales taxes, value added taxes, and other taxes we collect concurrent with revenue-producing activities are excluded from revenue. We have elected to recognize the cost for freight and shipping costs as part of cost of product sales when control over our products (i.e. delivery) has transferred to the customer.
Use of Estimates. In recognizing revenue for variable consideration arrangements, the amount of variable consideration recognized is limited so that it is probable that significant amounts of revenues will not be reversed in future periods when the uncertainty is resolved. For products returned by the customer, we estimate the expected returns based on an analysis of historical experience. For volume discounts earned by the customer, we estimate the discount (if any) based on our estimate of the total expected volume of products sold or services to be provided to the customer during the discount period. In certain contracts for the sale of CBFs, we may agree to issue credits for the repurchase of reclaimable used fluids from certain customers at an agreed price that is based on the condition of the fluids.
Contract Assets and Liabilities. We consider contract assets to be trade accounts receivable when we have an unconditional right to consideration and only the passage of time is required before payment is due. In certain instances, particularly those requiring customer specific documentation prior to invoicing, our invoicing of the customer is delayed until certain documentation requirements are met. In those cases, we recognize a contract asset rather than a billed trade accounts receivable until we are able to invoice the customer. Contract assets, along with billed trade accounts receivable, are included in trade accounts receivable in our consolidated balance sheets.
We classify contract liabilities as unearned income in our consolidated balance sheets. Unearned income includes amounts in which the Company was contractually allowed to invoice prior to satisfying the associated performance obligations.
Operating Costs
Cost of product sales includes direct and indirect costs of manufacturing and producing our products, including raw materials, fuel, utilities, labor, overhead, repairs and maintenance, materials, services, transportation, warehousing, equipment rentals, insurance, and certain taxes. Cost of services includes operating expenses we incur in delivering our services, including labor, equipment rental, fuel, repair and maintenance, transportation, overhead, insurance, and certain taxes. We include in product sales revenues the reimbursements we receive from customers for shipping and handling costs. Shipping and handling costs are included in cost of product sales. Amounts we incur for “out-of-pocket” expenses in the delivery of our services are recorded as cost of services. Reimbursements for “out-of-pocket” expenses we incur in the delivery of our services are recorded as service revenues. Depreciation, amortization, and accretion includes depreciation expense for all of our facilities, equipment and vehicles, amortization expense on our intangible assets, and accretion expense related to our decommissioning and other asset retirement obligations.
We include in general and administrative expense all costs not identifiable to our specific product or service operations, including divisional and general corporate overhead, professional services, corporate office costs, sales and marketing expenses, insurance, and certain taxes.
Equity-Based Compensation
We have various equity incentive compensation plans which provide for the granting of restricted common stock, options for the purchase of our common stock, and other performance-based, equity-based compensation awards to our executive officers, key employees, nonexecutive officers, and directors. Total equity-based compensation expense, net of taxes, for the three years ended December 31, 2020, 2019, and 2018, was $4.3 million, $4.6 million and $5.3 million, respectively. For further discussion of equity-based compensation, see Note 14 – “Equity-Based Compensation and Other”.
Mineral Resources Arrangements
We are party to agreements in which Standard Lithium has the right to explore, produce and extract lithium in our Arkansas leases as well as additional potential resources in the Mojave region of California. The Company receives cash and stock of Standard Lithium (TSXV: SLL) under the terms of the arrangements. The cash and stock component of consideration received is initially recorded as unearned income based on the quoted market price at the time the stock is received, then recognized in income over the contract term. During the years ended December 31, 2020, 2019 and 2018, income from this arrangement was 3.1 million, 1.1 million and 1.0 million, respectively, including the value of cash and stock received, and changes in the value of stock held. This income is included in other income (expense), net in our consolidated statements of operations. Unearned revenue associated with these agreements was 0.9 million and 0.2 million as of December 31, 2020 and 2019, respectively, and is included in unearned income on our consolidated balance sheets. See Note 15 - “Fair Value Measurements” for further discussion.
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis amounts. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date. A portion of the carrying value of certain deferred tax assets are subject to a valuation allowance. See Note 16 – “Income Taxes” for further discussion.
In January 2018, the FASB released guidance on the accounting for tax on the global intangible low-taxed income (“GILTI”) provisions of the Tax Reform Act. The GILTI provisions impose a tax on foreign income in excess of a deemed return on tangible assets of foreign corporations. The guidance indicates that either accounting for deferred taxes related to GILTI inclusions or to treat any taxes on GILTI inclusions as period costs are both acceptable methods subject to an accounting policy election. We elected to account for GILTI as a period cost in the year the tax is incurred.
Noncontrolling Interests
Noncontrolling interests represent third-party ownership in the net assets of the Company’s consolidated subsidiaries and are presented as a component of equity. Substantially all of the Company’s noncontrolling interests represent third-party ownership in CCLP.
Accumulated Other Comprehensive Income (Loss)
Certain of our international operations maintain their accounting records in the local currencies that are their functional currencies. For these operations, the functional currency financial statements are converted to United States dollar equivalents, with the effect of the foreign currency translation adjustment reflected as a component of accumulated other comprehensive income (loss). Accumulated other comprehensive income (loss) is included in equity in the accompanying consolidated balance sheets and consists of the cumulative currency translation adjustments associated with such international operations. Activity within our accumulated other comprehensive income (loss) is not subject to reclassifications to net income.
Income (Loss) per Common Share
The calculation of basic and diluted earnings per share excludes losses attributable to noncontrolling interests. The calculation of basic earnings per share excludes any dilutive effects of equity awards or warrants. The
calculation of diluted earnings per share includes the effect of equity awards and warrants, if dilutive, which is computed using the treasury stock method during the periods such equity awards and warrants were outstanding. For the years ended December 31, 2020, 2019, and 2018, the average diluted shares outstanding excludes the impact of all outstanding equity awards and warrants, as the inclusion of these shares would have been anti-dilutive due to the net losses recorded during the year.
Foreign Currency Translation
We have designated the euro, the British pound, the Norwegian krone, the Canadian dollar, the Brazilian real, and the Mexican peso as the functional currencies for our operations in Finland and Sweden, the United Kingdom, Norway, Canada, Brazil, and certain of our operations in Mexico, respectively. The U.S. dollar is the designated functional currency for all of our other foreign operations. The cumulative translation effects of translating the applicable accounts from the functional currencies into the U.S. dollar at current exchange rates are included as a separate component of equity. Foreign currency exchange (gains) and losses are included in other (income) expense, net, and totaled $2.7 million, $(0.5) million, and $1.3 million for the years ended December 31, 2020, 2019 and 2018, respectively.
On June 30, 2018, we determined the economy in Argentina to be highly inflationary. As a result of this determination and in accordance with U.S. GAAP, on July 1, 2018, the functional currency of our operations in Argentina was changed from the Argentine peso to the U.S. dollar. The remeasurement did not have a material impact on our consolidated financial position or results of operations.
Fair Value Measurements
We utilize fair value measurements to account for certain items and account balances within our consolidated financial statements. Fair value measurements are utilized on a recurring basis in the determination of the carrying values of certain liabilities, including the liabilities for the warrants to purchase 11.2 million shares of our common stock (the “Warrants”) and our foreign currency derivative contracts. See Note 15 - “Fair Value Measurements” for further discussion.
Fair value measurements are also utilized on a nonrecurring basis in certain circumstances, such as in the allocation of purchase consideration for acquisition transactions to the assets and liabilities acquired, including intangible assets and goodwill (a Level 3 fair value measurement), the initial recording of our asset retirement obligations, and for the impairment of long-lived assets, including goodwill (a Level 3 fair value measurement).
New Accounting Pronouncements
Standards adopted in 2020
In August 2018, the FASB issued ASU 2018-15, “Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”. ASU 2018-15 clarifies the accounting for implementation costs in cloud computing arrangements. On January 1, 2020, we adopted ASU 2018-15. The adoption of this standard did not have a material impact on our consolidated financial statements.
Standards not yet adopted
In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”. ASU 2016-13 amends the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses on financial instruments not accounted for at fair value through net income. The provisions require credit impairments to be measured over the contractual life of an asset and developed with consideration for past events, current conditions, and forecasts of future economic information. Credit impairment will be accounted for as an allowance for credit losses deducted from the amortized cost basis at each reporting date. Updates at each reporting date after initial adoption will be recorded through selling, general, and administrative expense. ASU 2016-13 is effective for us the first quarter of fiscal 2023. We continue to assess the potential effects of these changes to our consolidated financial statements.
In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes”. ASU 2019-12 simplifies the accounting for income taxes by eliminating certain exceptions related to intraperiod tax allocation, interim period income tax calculation methodology, and the recognition of deferred tax liabilities for outside basis differences. It also simplifies certain aspects of accounting for franchise taxes and clarifies the accounting for transactions that results in a step-up in the tax basis of goodwill. ASU 2019-12 is effective for us the first quarter of fiscal 2021. We continue to assess the potential effects of these changes to our consolidated financial statements
In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848)”, which provides optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships, and other transactions affected by the discontinuation of the London Interbank Offered Rate (“LIBOR”) or by another reference rate expected to be discontinued. The amendments are effective for all entities as of March 12, 2020 through December 31, 2022. Entities may elect to apply the amendments for contract modifications as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020. As of December 31, 2020, we have not modified our credit agreements to remove references to LIBOR. We are currently evaluating the impact of the provisions of ASU 2020-04 on our consolidated financial statements.
NOTE 3 – DISCONTINUED OPERATIONS
As discussed in Note 18 - “Subsequent Event,” on January 29, 2021, we entered into the Purchase and Sale Agreement with Spartan pursuant to which we sold the general partner of CCLP, including the IDRs in CCLP and approximately 23.1% of the outstanding limited partner interests in CCLP. Our interest in CCLP and the general partner represented substantially all of our Compression Division. As of December 31, 2020, our Compression Division met the held for sale criteria and is reflected as discontinued operations in our financial statements for all periods presented. In addition, as discussed in Note 11 - “Acquisitions and Dispositions,” on March 1, 2018, we closed a series of related transactions that resulted in the disposition of our Offshore Division. As a result, we have accounted for our Offshore Division, consisting of our Offshore Services and Maritech segments, as discontinued operations.
During the third quarter of 2019, as a result of the bankruptcy filing of Epic Companies, LLC, we recorded a reserve for the full amount of certain other receivables of discontinued operations related to our offshore division in the amount of $1.5 million and for the full amount of a $7.5 million promissory note, including accrued interest, that we received as part of the consideration for the sale. See Note 12 - “Commitments and Contingencies” for further discussion.
Our consolidated balance sheets and consolidated statements of operations report discontinued operations separate from continuing operations. Our consolidated statements of comprehensive income, statements of equity
and statements of cash flows combine continuing and discontinued operations. A summary of financial information related to our discontinued operations is as follows:
Reconciliation of the Line Items Constituting Pretax Loss from Discontinued Operations to the After-Tax Loss from Discontinued Operations
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2020
|
|
|
Compression
|
|
Offshore Services
|
|
Total
|
|
Revenue
|
$
|
338,246
|
|
|
$
|
—
|
|
|
$
|
338,246
|
|
|
Cost of revenues
|
212,253
|
|
|
(330)
|
|
|
211,923
|
|
|
Depreciation, amortization, and accretion
|
80,533
|
|
|
—
|
|
|
80,533
|
|
|
Impairments and other charges
|
20,841
|
|
|
—
|
|
|
20,841
|
|
|
General and administrative expense
|
37,895
|
|
|
473
|
|
|
38,368
|
|
|
Interest expense, net
|
52,771
|
|
|
—
|
|
|
52,771
|
|
|
|
|
|
|
|
|
|
Other (income) expense, net
|
2,688
|
|
|
—
|
|
|
2,688
|
|
|
Pretax loss from discontinued operations
|
(68,735)
|
|
|
(143)
|
|
|
(68,878)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision
|
|
|
|
|
3,211
|
|
|
Loss from discontinued operations
|
|
|
|
|
(72,089)
|
|
|
Loss from discontinued operations attributable to noncontrolling interest
|
|
|
|
|
47,898
|
|
|
Loss from discontinued operations attributable to TETRA stockholders
|
|
|
|
|
$
|
(24,191)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2019
|
|
|
Compression
|
|
Offshore Services
|
|
Maritech
|
|
Total
|
|
Revenue
|
476,692
|
|
|
—
|
|
|
—
|
|
|
476,692
|
|
|
Cost of revenues
|
320,037
|
|
|
(192)
|
|
|
—
|
|
|
319,845
|
|
|
Depreciation, amortization, and accretion
|
76,663
|
|
|
52
|
|
|
—
|
|
|
76,715
|
|
|
General and administrative expense
|
43,281
|
|
|
2,618
|
|
|
—
|
|
|
45,899
|
|
|
Interest expense, net
|
51,974
|
|
|
—
|
|
|
—
|
|
|
51,974
|
|
|
CCLP Series A Preferred Units fair value adjustment (income) expense
|
1,309
|
|
|
—
|
|
|
—
|
|
|
1,309
|
|
|
Other (income) expense, net
|
(558)
|
|
|
117
|
|
|
118
|
|
|
(323)
|
|
|
Pretax loss from discontinued operations
|
(16,014)
|
|
|
(2,595)
|
|
|
(118)
|
|
|
(18,727)
|
|
|
Pretax loss on disposal of discontinued operations
|
|
|
|
|
|
|
(7,500)
|
|
|
Total pretax loss from discontinued operations
|
|
|
|
|
|
|
(26,227)
|
|
|
Income tax provision
|
|
|
|
|
|
|
3,353
|
|
|
Loss from discontinued operations
|
|
|
|
|
|
|
(29,580)
|
|
|
Loss from discontinued operations attributable to noncontrolling interest
|
|
|
|
|
|
|
13,538
|
|
|
Loss from discontinued operations attributable to TETRA stockholders
|
|
|
|
|
|
|
(16,042)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2018
|
|
|
Compression
|
|
Offshore Services
|
|
Maritech
|
|
Total
|
|
Revenue
|
438,673
|
|
|
4,487
|
|
|
187
|
|
|
443,347
|
|
|
Cost of revenues
|
309,156
|
|
|
11,151
|
|
|
139
|
|
|
320,446
|
|
|
Depreciation, amortization, and accretion
|
70,500
|
|
|
1,873
|
|
|
212
|
|
|
72,585
|
|
|
General and administrative expense
|
39,544
|
|
|
1,917
|
|
|
187
|
|
|
41,648
|
|
|
Interest expense, net
|
51,905
|
|
|
—
|
|
|
—
|
|
|
51,905
|
|
|
CCLP Series A Preferred Units fair value adjustment (income) expense
|
(733)
|
|
|
—
|
|
|
—
|
|
|
(733)
|
|
|
Other (income) expense, net
|
2,099
|
|
|
(1,036)
|
|
|
—
|
|
|
1,063
|
|
|
Pretax loss from discontinued operations
|
(33,798)
|
|
|
(9,418)
|
|
|
(351)
|
|
|
(43,567)
|
|
|
Pretax loss on disposal of discontinued operations
|
|
|
|
|
|
|
(34,072)
|
|
|
Total pretax loss from discontinued operations
|
|
|
|
|
|
|
(77,639)
|
|
|
Income tax provision
|
|
|
|
|
|
|
289
|
|
|
Loss from discontinued operations
|
|
|
|
|
|
|
(77,928)
|
|
|
Loss from discontinued operations attributable to noncontrolling interest
|
|
|
|
|
|
|
22,623
|
|
|
Loss from discontinued operations attributable to TETRA stockholders
|
|
|
|
|
|
|
$
|
(55,305)
|
|
Reconciliation of Major Classes of Assets and Liabilities of the Discontinued Operations to Amounts Presented Separately in the Statement of Financial Position
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
|
Compression
|
|
Offshore Services
|
|
Maritech
|
|
Total
|
|
Carrying amounts of major classes of assets included as part of discontinued operations
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
16,577
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
16,577
|
|
|
Trade receivables
|
43,837
|
|
|
—
|
|
|
—
|
|
|
43,837
|
|
|
Inventories
|
31,220
|
|
|
—
|
|
|
—
|
|
|
31,220
|
|
|
Other current assets
|
5,231
|
|
|
—
|
|
|
—
|
|
|
5,231
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant, and equipment
|
551,401
|
|
|
—
|
|
|
—
|
|
|
551,401
|
|
|
Other assets
|
61,740
|
|
|
—
|
|
|
—
|
|
|
61,740
|
|
|
|
|
|
|
|
|
|
|
|
Total assets associated with discontinued operations(1)
|
$
|
96,865
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
710,006
|
|
|
|
|
|
|
|
|
|
|
|
Carrying amounts of major classes of liabilities included as part of discontinued operations
|
|
|
|
|
|
|
|
|
Trade payables
|
$
|
19,766
|
|
|
$
|
1,222
|
|
|
$
|
—
|
|
|
$
|
20,988
|
|
|
Unearned income
|
269
|
|
|
—
|
|
|
—
|
|
|
269
|
|
|
Accrued liabilities and other
|
36,318
|
|
|
352
|
|
|
228
|
|
|
36,898
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, net
|
638,631
|
|
|
—
|
|
|
—
|
|
|
638,631
|
|
|
Other liabilities
|
37,253
|
|
|
—
|
|
|
—
|
|
|
37,253
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities associated with discontinued operations(1)
|
$
|
732,237
|
|
|
$
|
1,574
|
|
|
$
|
228
|
|
|
$
|
734,039
|
|
(1) All assets and liabilities associated with discontinued operations of our former Compression Division are classified as current as of December 31, 2020 due to completion of the GP Sale within one year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
Compression
|
|
Offshore Services
|
|
Maritech
|
|
Total
|
|
Carrying amounts of major classes of assets included as part of discontinued operations
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
2,370
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,370
|
|
|
Trade receivables
|
64,724
|
|
|
—
|
|
|
—
|
|
|
64,724
|
|
|
Inventories
|
56,037
|
|
|
—
|
|
|
—
|
|
|
56,037
|
|
|
Other current assets
|
4,210
|
|
|
—
|
|
|
—
|
|
|
4,210
|
|
|
Current assets associated with discontinued operations (1)
|
$
|
127,341
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
127,341
|
|
|
Property, plant, and equipment
|
642,367
|
|
|
—
|
|
|
—
|
|
|
642,367
|
|
|
Other assets
|
52,991
|
|
|
—
|
|
|
—
|
|
|
52,991
|
|
|
Long-term assets associated with discontinued operations (1)
|
695,358
|
|
|
—
|
|
|
—
|
|
|
695,358
|
|
|
Total major classes of assets of the discontinued operations
|
$
|
822,699
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
822,699
|
|
|
|
|
|
|
|
|
|
|
|
Carrying amounts of major classes of liabilities included as part of discontinued operations
|
|
|
|
|
|
|
|
|
Trade payables
|
$
|
47,837
|
|
|
$
|
1,233
|
|
|
$
|
—
|
|
|
$
|
49,070
|
|
|
Unearned income
|
9,505
|
|
|
—
|
|
|
—
|
|
|
9,505
|
|
|
Accrued liabilities and other
|
43,022
|
|
|
745
|
|
|
120
|
|
|
43,887
|
|
|
Current liabilities associated with discontinued operations (1)
|
$
|
100,364
|
|
|
$
|
1,978
|
|
|
$
|
120
|
|
|
$
|
102,462
|
|
|
Long-term debt, net
|
638,238
|
|
|
—
|
|
|
—
|
|
|
638,238
|
|
|
Other liabilities
|
15,066
|
|
|
—
|
|
|
—
|
|
|
15,066
|
|
|
Long-term liabilities associated with discontinued operations (1)
|
653,304
|
|
|
—
|
|
|
—
|
|
|
653,304
|
|
|
Total major classes of liabilities of the discontinued operations
|
$
|
753,668
|
|
|
$
|
1,978
|
|
|
$
|
120
|
|
|
$
|
755,766
|
|
NOTE 4 — REVENUE FROM CONTRACTS WITH CUSTOMERS
Our contract asset balances, primarily associated with customer documentation requirements, were $12.8 million, $25.3 million and $38.3 million as of December 31, 2020, 2019 and 2018, respectively. The decrease in contract asset balances is primarily due to lower activity in our Water & Flowback Services Division driven by the significant reduction in capital spending by our customers in response to the decline in oil prices. Contract assets, along with billed trade accounts receivable, are included in trade accounts receivable in our consolidated balance sheets.
Unearned income includes amounts in which the Company was contractually allowed to invoice prior to satisfying the associated performance obligations. Unearned income balances were $1.9 million and $0.2 million as of December 31, 2020 and 2019, respectively, and vary based on the timing of invoicing and performance obligations being met. Revenues recognized during the years ended December 31, 2020 and 2019 deferred as of the end of the preceding year was not significant. During the years ended December 31, 2020, 2019 and 2018, contract costs were not significant.
Disaggregation of Revenue. We disaggregate revenue from contracts with customers into Product Sales and Services within each segment, as noted in our two reportable segments in Note 17 - Industry Segments and Geographic Information. In addition, we disaggregate revenue from contracts with customers by geography based on the following table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
(In Thousands)
|
|
Completion Fluids & Products
|
|
|
|
|
|
|
U.S.
|
$
|
100,076
|
|
|
$
|
149,191
|
|
|
$
|
129,160
|
|
|
International
|
142,585
|
|
|
130,064
|
|
|
128,248
|
|
|
|
242,661
|
|
|
279,255
|
|
|
257,408
|
|
|
Water & Flowback Services
|
|
|
|
|
|
|
U.S.
|
125,759
|
|
|
262,093
|
|
|
261,238
|
|
|
International
|
9,295
|
|
|
19,893
|
|
|
41,834
|
|
|
|
135,054
|
|
|
281,986
|
|
|
303,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interdivision eliminations
|
|
|
|
|
|
|
U.S.
|
—
|
|
|
—
|
|
|
5
|
|
|
International
|
—
|
|
|
—
|
|
|
(383)
|
|
|
|
—
|
|
|
—
|
|
|
(378)
|
|
|
Total Revenue
|
|
|
|
|
|
|
U.S.
|
225,835
|
|
|
411,284
|
|
|
390,403
|
|
|
International
|
151,880
|
|
|
149,957
|
|
|
169,699
|
|
|
|
$
|
377,715
|
|
|
$
|
561,241
|
|
|
$
|
560,102
|
|
NOTE 5 — GOODWILL
Our Water & Flowback Services Division consists of two reporting units, Production Testing and Water Management. During the third quarter of 2019, as part of our internal long-term outlook for each of these reporting units, we updated our assessment of the Water Management reporting unit and determined that the current decreased energy industry outlook was an indicator requiring further analysis for impairment of goodwill. As part of the first step of goodwill impairment testing for our Water Management reporting unit, the only reporting unit with goodwill, we updated our assessment of the future cash flows, applying expected long-term growth rates, discount rates, and terminal values that we consider reasonable for the reporting unit. We calculated a present value of the cash flows for the Water Management reporting unit to arrive at an estimate of fair value using a combination of the income approach and the market approach. Based on these assumptions, we determined that the fair value of the Water Management reporting unit exceeded its carrying value, resulting in no impairment at September 30, 2019.
During the fourth quarter of 2019, coinciding with the timing of our annual goodwill assessment, there was further decline in the energy industry outlook resulting in decreased expected future cash flows for our Water Management reporting unit. As part of the first step of goodwill impairment testing for our Water Management reporting unit, the only reporting unit with goodwill, we updated our assessment of the future cash flows, applying expected long-term growth rates, discount rates, and terminal values that we consider reasonable for the reporting unit. We calculated a present value of the cash flows for the Water Management reporting unit to arrive at an estimate of fair value using a combination of the income approach and the market approach. Based on these assumptions, we determined that the fair value of the Water Management reporting unit was less than its carrying value indicating an impairment. The amount of impairment is calculated based on the difference between the fair value and carrying value in accordance with our early adoption of ASU 2017-04 “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This resulted in an impairment of the entire goodwill balance of $25.8 million at December 31, 2019.
The changes in the carrying amount of goodwill for the Water & Flowback Services reporting segment were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
(In Thousands)
|
|
Balance as of December 31, 2017
|
|
|
|
|
|
|
|
$
|
6,636
|
|
|
Goodwill acquired during the year
|
|
|
|
|
|
|
|
19,223
|
|
|
Balance as of December 31, 2018
|
|
|
|
|
|
|
|
25,859
|
|
|
Goodwill impaired during the year
|
|
|
|
|
|
|
|
(25,784)
|
|
|
Goodwill adjustments
|
|
|
|
|
|
|
|
(75)
|
|
|
Balance as of December 31, 2019 and 2020
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 6 — IMPAIRMENTS AND OTHER CHARGES
Impairments of Long-Lived Assets
During 2020, we recorded an impairment charge of $0.6 million primarily related to a right of use asset for the lease of our Canada office within our Water & Flowback Services Division as we ceased use of the office during the year.
During the fourth quarter of 2019, we recorded an impairment of $91.6 million in our Completion Fluids & Products Division related to our El Dorado, Arkansas calcium chloride production plant facility assets. The impairment charge is primarily the result of a reduction in the cost of raw materials for certain of our other chemical production plants, following the execution of a long-term raw material supply agreement during the fourth quarter of 2019. As a result, we expect to reduce our dependence on calcium chloride produced at the El Dorado facility, which uses a different production process, involving mechanical evaporation. In addition, demand for calcium chloride from the El Dorado plant is expected to be reduced due to general market conditions in the oil and gas industry. Using the reduced expected future net cash flows on an undiscounted basis, we determined that the carrying value of the El Dorado facility was not recoverable. Fair value of the El Dorado facility was determined using a fair value in-exchange assumption, and the difference between the carrying value of the El Dorado facility asset group and its indicated fair value was recorded as an impairment. Also during the fourth quarter of 2019, we recorded an impairment of $0.3 million related to certain equipment assets in our Water & Flowback Services Division.
During the third quarter of 2018, as a result of decreased expected future cash flows from a specific customer contract, we recorded a long-lived asset impairment of $2.9 million on an identified intangible asset within the Water & Flowback Services segment.
NOTE 7 – INVENTORIES
Components of inventories, net of reserve, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2020
|
|
2019
|
|
|
|
(In Thousands)
|
|
Finished goods
|
|
$
|
68,121
|
|
|
$
|
70,135
|
|
|
Raw materials
|
|
2,910
|
|
|
4,125
|
|
|
Parts and supplies
|
|
4,001
|
|
|
4,979
|
|
|
Work in progress
|
|
1,626
|
|
|
1,234
|
|
|
Total inventories
|
|
$
|
76,658
|
|
|
$
|
80,473
|
|
Finished goods inventories include newly manufactured clear brine fluids as well as used brines that are repurchased from certain customers for recycling.
NOTE 8 — LEASES
We have operating leases for some of our transportation equipment, office space, warehouse space, operating locations, and machinery and equipment. We have finance leases for certain facility storage tanks and equipment rentals. These finance leases are not material to our financial statements. Our leases have remaining lease terms ranging from 1 to 16 years. Some of our leases have options to extend for various periods, while some have termination options with prior notice of generally 30 days or six months. The office space, warehouse space, operating location leases, and machinery and equipment leases generally require us to pay all maintenance and insurance costs.
Our corporate headquarters facility located in The Woodlands, Texas, was sold on December 31, 2012, pursuant to a sale and leaseback transaction. As a condition to the completion of the purchase and sale of the facility, the parties entered into a lease agreement for the facility having an initial lease term of 15 years, which is classified as an operating lease. Under the terms of the lease agreement, we have the ability to extend the lease for five successive five-year periods at base rental rates to be determined at the time of each extension.
Components of lease expense, included in either cost of revenues or general and administrative expense based on the use of the underlying asset, are as follows (inclusive of lease expense for leases not included on our consolidated balance sheet based on our accounting policy election to exclude leases with a term of 12 months or less):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2020
|
|
2019
|
|
|
(In Thousands)
|
|
Operating lease expense
|
$
|
13,946
|
|
|
$
|
15,131
|
|
|
Short-term lease expense
|
17,125
|
|
|
36,348
|
|
|
Total lease expense
|
$
|
31,071
|
|
|
$
|
51,479
|
|
Rental expense for all operating leases was $31.1 million, $51.4 million, and $35.3 million for the years ended December 31, 2020, 2019, and 2018, respectively. At December 31, 2020, future minimum rental receipts under a non-cancelable sublease for office space in one of our locations totaled $5.2 million. For the years ended December 31, 2020 and 2019, we recognized sublease income of $1.0 million. Variable rent expense was not material.
Supplemental cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2020
|
|
2019
|
|
|
(In Thousands)
|
|
Cash paid for amounts included in the measurement of lease liabilities:
|
|
|
|
|
Operating cash flows - operating leases
|
$
|
13,612
|
|
|
$
|
15,064
|
|
|
|
|
|
|
|
Right-of-use assets obtained in exchange for lease obligations:
|
|
|
|
|
Operating leases
|
$
|
5,612
|
|
|
$
|
3,944
|
|
Supplemental balance sheet information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
|
|
(In Thousands)
|
|
Operating leases:
|
|
|
|
|
Operating lease right-of-use assets
|
$
|
43,448
|
|
|
$
|
47,125
|
|
|
|
|
|
|
|
Accrued liabilities and other
|
$
|
8,795
|
|
|
$
|
9,144
|
|
|
Operating lease liabilities
|
$
|
37,569
|
|
|
$
|
40,097
|
|
|
Total operating lease liabilities
|
$
|
46,364
|
|
|
$
|
49,241
|
|
Additional operating lease information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
|
Weighted average remaining lease term:
|
|
|
|
|
Operating leases
|
6.8 years
|
|
7.2 years
|
|
|
|
|
|
|
Weighted average discount rate:
|
|
|
|
|
Operating leases
|
9.62
|
%
|
|
9.56
|
%
|
Future minimum lease payments by year and in the aggregate, under non-cancelable operating leases with terms in excess of one year consist of the following at December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
|
|
|
|
(In Thousands)
|
|
2021
|
|
|
|
$
|
12,798
|
|
|
2022
|
|
|
|
10,910
|
|
|
2023
|
|
|
|
8,673
|
|
|
2024
|
|
|
|
7,202
|
|
|
2025
|
|
|
|
5,332
|
|
|
Thereafter
|
|
|
|
18,460
|
|
|
Total lease payments
|
|
|
|
63,375
|
|
|
Less imputed interest
|
|
|
|
(17,011)
|
|
|
Total lease liabilities
|
|
|
|
$
|
46,364
|
|
NOTE 9 — ACCRUED LIABILITIES
Accrued liabilities are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2020
|
|
2019
|
|
|
|
(In Thousands)
|
|
Compensation and employee benefits
|
|
$
|
14,336
|
|
|
$
|
18,657
|
|
|
Operating lease liabilities, current portion
|
|
8,795
|
|
|
9,144
|
|
|
Accrued taxes
|
|
4,323
|
|
|
6,894
|
|
|
Accrued interest
|
|
2,951
|
|
|
299
|
|
|
Accrued capital expenditures
|
|
194
|
|
|
978
|
|
|
Other accrued liabilities
|
|
8,192
|
|
|
8,883
|
|
|
Total accrued liabilities and other
|
|
$
|
38,791
|
|
|
$
|
44,855
|
|
NOTE 10 — LONG-TERM DEBT AND OTHER BORROWINGS
Consolidated long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2020
|
|
December 31,
2019
|
|
|
|
|
(In Thousands)
|
|
TETRA
|
|
Scheduled Maturity
|
|
|
|
|
Asset-based credit agreement
|
|
September 10, 2023
|
$
|
—
|
|
|
$
|
—
|
|
|
Term credit agreement (1)
|
|
September 10, 2025
|
199,894
|
|
|
204,633
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
$
|
199,894
|
|
|
$
|
204,633
|
|
(1) Net of unamortized discount of $5.5 million and $6.4 million as of December 31, 2020 and 2019, respectively, and net of unamortized deferred financing costs of $8.2 million and $9.5 million as of December 31, 2020 and 2019, respectively.
Scheduled maturities for the next five years and thereafter are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
|
|
(In Thousands)
|
|
2021
|
|
$
|
—
|
|
|
2022
|
|
—
|
|
|
2023
|
|
—
|
|
|
2024
|
|
—
|
|
|
2025
|
|
213,549
|
|
|
Thereafter
|
|
—
|
|
|
Total maturities
|
|
$
|
213,549
|
|
Our credit agreements contain certain affirmative and negative covenants, including covenants that restrict the ability to pay dividends or other restricted payments. As of December 31, 2020, we were in compliance with all covenants under the credit agreements.
Asset-Based Credit Agreement. As of December 31, 2020, TETRA had no balance outstanding and had $6.6 million in letters of credit against its asset-based lending agreement (“ABL Credit Agreement”). The ABL Credit Agreement provides for a senior secured revolving credit facility of up to $100 million, subject to a borrowing base to be determined by reference to the value of inventory and accounts receivable, and includes a sublimit of $20.0 million for letters of credit and a swingline loan sublimit of $10.0 million. The maturity date of the ABL Credit Agreement is September 10, 2023. The ABL Credit Agreement is subject to compliance with the covenants, borrowing base, and other provisions of the agreement that may limit borrowings, TETRA had an availability of $24.6 million under this agreement as of December 31, 2020. Because there was no outstanding balance on this ABL Credit Agreement as of December 31, 2020 or 2019, associated deferred financing costs of $1.0 million were classified as other long-term assets on the accompanying consolidated balance sheet.
Borrowings under the ABL Credit Agreement bear interest at a rate per annum equal to, at the option of TETRA, either (i) LIBOR plus a margin based upon a fixed charge coverage ratio or (ii) a base rate plus a margin based on a fixed charge coverage ratio. The base rate is determined by reference to the highest of (a) the prime rate of interest as announced from time to time by JPMorgan Chase Bank, N.A. (b) the Federal Funds Effective Rate (as defined in the ABL Credit Agreement) plus 0.5% per annum and (c) LIBOR (adjusted to reflect any required bank reserves) for a one-month period on such day plus 1.0% per annum. Borrowings outstanding have an applicable margin ranging from 1.75% to 2.25% per annum for LIBOR-based loans and 0.75% to 1.25% per annum for base-rate loans, based upon the applicable fixed charge coverage ratio. In addition to paying interest on the outstanding principal under the ABL Credit Agreement, TETRA is required to pay a commitment fee in respect of the unutilized commitments at an applicable rate ranging from 0.375% to 0.5% per annum, paid monthly in arrears based on utilization of the commitments under the ABL Credit Agreement. TETRA is also required to pay a customary letter of credit fee equal to the applicable margin on LIBOR-based loans and fronting fees.
All obligations under the ABL Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a security interest for the benefit of the ABL Lenders on substantially all of the personal property of TETRA and certain subsidiaries of TETRA, the equity interests in certain domestic subsidiaries, and a maximum of 65% of the equity interests in certain foreign subsidiaries.
Term Credit Agreement
As of December 31, 2020 TETRA had $199.9 million outstanding, net of unamortized discounts and unamortized deferred financing costs under the Term Credit Agreement
Borrowings under the Term Credit Agreement bear interest at a rate per annum equal to, at the option of TETRA, either (i) LIBOR plus a margin of 6.25% per annum or (ii) a base rate plus a margin of 5.25% per annum. In addition to paying interest on the outstanding principal under the Term Credit Agreement, TETRA is required to pay a commitment fee in respect of the unutilized commitments at the rate of 1.0% per annum, paid quarterly in arrears based on utilization of the commitments under the Term Credit Agreement.
All obligations under the Term Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a security interest for the benefit of the Term Lenders on substantially all of the personal property of TETRA and certain of its subsidiaries, the equity interests in certain domestic subsidiaries, and a maximum of 65% of the equity interests in certain foreign subsidiaries.
NOTE 11 — ACQUISITIONS AND DISPOSITIONS
Acquisition of SwiftWater Energy Services
On February 28, 2018, pursuant to a purchase agreement dated February 13, 2018 (the “SwiftWater Purchase Agreement”), we purchased all of the equity interests in SwiftWater Energy Services, LLC (“SwiftWater”), which is engaged in the business of providing water management and water solutions to oil and gas operators in the Permian Basin market of Texas. Strategically, the acquisition of SwiftWater enhances our position as one of the leading integrated water management companies, providing water transfer, storage, and treatment services, along with proprietary automation technology and numerous other water-related services.
Under the terms of the SwiftWater Purchase Agreement, consideration of $42.0 million of cash, subject to a working capital adjustment, and 7,772,021 shares of our common stock (valued at $28.2 million) were paid at closing. The allocation of the purchase price to the SwiftWater net tangible assets and liabilities and identifiable intangible assets was final as of December 31, 2018. Contingent consideration in the amount of $10.0 million was paid to the sellers during 2019 based on 2018 performance. As of December 31, 2019, all contingent consideration had been paid.
Acquisition of JRGO Energy Services LLC
On December 6, 2018, we purchased JRGO Energy Services LLC (“JRGO”) for a cash purchase price of $7.6 million paid at closing, subject to a working capital adjustment. In addition, contingent consideration of $1.4 million was paid during 2019, based on JRGO’s performance during the fourth quarter of 2018. JRGO specializes in delivering comprehensive water management services for oil and gas operators, as well as municipal, state and federal organizations. The acquisition of JRGO broadens our footprint in the Appalachian region and is expected to provide our customers an enhanced, more efficient, diverse, and strategically positioned portfolio of integrated water management services in the Marcellus and Utica basins. The allocation of the purchase price to the JRGO net tangible assets and liabilities and identifiable intangible assets was final as of December 31, 2019.
Sale of Offshore Division
On March 1, 2018, we closed a series of related transactions that resulted in the disposition of our Offshore Division. Pursuant to an Asset Purchase and Sale Agreement (the “Maritech Asset Purchase Agreement”) with Orinoco Natural Resources, LLC (“Orinoco”), Orinoco purchased certain remaining offshore oil, gas and mineral leases and related assets of Maritech (the “Maritech Properties”). Immediately thereafter, we closed the transactions contemplated by a Membership Interest Purchase and Sale Agreement (the “Maritech Equity Purchase Agreement”) with Orinoco, whereby Orinoco purchased all of the equity interests of Maritech (the “Maritech Equity Interests”). Immediately thereafter, we closed the transactions contemplated by an Equity Interest Purchase Agreement (the
“Offshore Services Purchase Agreement”) with Epic Offshore Specialty, LLC, an affiliate of Orinoco (“Epic Offshore”), whereby Epic Offshore (the “Offshore Services Sale”) purchased all of the equity interests in the wholly owned subsidiaries that comprised our Offshore Services segment operations (the “Offshore Services Equity Interests”).
Under the terms of the Maritech Asset Purchase Agreement, the Maritech Equity Purchase Agreement, and the Offshore Services Purchase Agreement, the consideration delivered by Orinoco and Epic Offshore for the Maritech Properties, the Maritech Equity Interests and the Offshore Services Equity Interests consisted of (i) the assumption by Orinoco of substantially all of the liabilities and obligations relating to the ownership, operation and condition of the Maritech Properties and the provision of certain indemnities by Orinoco to us under the Maritech Asset Purchase Agreement, (ii) the assumption by Orinoco of substantially all of the liabilities of Maritech and the provision of certain indemnities by Orinoco under the Maritech Equity Purchase Agreement, (iii) the assumption by Epic Offshore of substantially all of the liabilities of the Offshore Services Equity Interests relating to the periods following the closing of the Offshore Services Sale and the provision of certain indemnities by Epic Offshore under the Offshore Services Purchase Agreement, (iv) cash in the amount $3.1 million (v) a promissory note in the original principal amount of $7.5 million payable by Epic Offshore to us in full, together with interest at a rate of 1.52% per annum, on December 31, 2019, (vi) performance by Orinoco under a Bonding Agreement executed in connection with the Maritech Asset Purchase Agreement and the Maritech Equity Purchase Agreement whereby Orinoco provided at closing non-revocable performance bonds in an amount equal to $46.8 million to cover the performance by Orinoco and Maritech of the asset retirement obligations of Maritech, and (vii) the delivery of a personal guaranty agreement from Thomas M. Clarke and Ana M. Clarke guaranteeing the payment obligations of Orinoco under the Bonding Agreement (collectively, the “Transaction Consideration”). See Note 12 - “Commitments and Contingencies” for further discussion of the promissory note and the Bonding Agreement.
As a result of these transactions, we have effectively exited the businesses of our Offshore Services and Maritech segments, and these operations are reflected as discontinued operations in our consolidated financial statements. See Note 3 - “Discontinued Operations” for further discussion.
NOTE 12 — COMMITMENTS AND CONTINGENCIES
Litigation
We are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not consider it reasonably possible that a loss resulting from such lawsuits or other proceedings in excess of any amounts accrued has been incurred that is expected to have a material adverse impact on our financial condition, results of operations, or liquidity.
Product Purchase Obligations
In the normal course of our Completion Fluids & Products Division operations, we enter into supply agreements with certain manufacturers of various raw materials and finished products. Some of these agreements have terms and conditions that specify a minimum or maximum level of purchases over the term of the agreement. Other agreements require us to purchase the entire output of the raw material or finished product produced by the manufacturer. Our purchase obligations under these agreements apply only with regard to raw materials and finished products that meet specifications set forth in the agreements. We recognize a liability for the purchase of such products at the time we receive them. As of December 31, 2020, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Completion Fluids & Products Division’s supply agreements was approximately $85.3 million, including $9.5 million per year from 2021 to 2025 and $37.8 million thereafter, extending through 2029. Amounts purchased under these agreements for each of the years ended December 31, 2020, 2019, and 2018, was $17.3 million, $18.7 million, and $18.0 million, respectively.
Contingencies of Discontinued Operations
In early 2018, we closed the Maritech Asset Purchase and Sale Agreement with Orinoco Natural Resources, LLC (“Orinoco”) that provided for the purchase by Orinoco of Maritech’s remaining oil and gas properties and related assets. Also in early 2018, we closed the Maritech Membership Interest Purchase and Sale Agreement with Orinoco that provided for the purchase by Orinoco of all of the outstanding membership interests in Maritech. As a result of these transactions, we have effectively exited the business of our former Maritech segment.
Under the Maritech Asset Purchase and Sale Agreement, Orinoco assumed all of Maritech’s decommissioning liabilities related to the leases sold to Orinoco (the “Orinoco Lease Liabilities”) and, under the Maritech Membership Interest Purchase and Sale Agreement, Orinoco assumed all other liabilities of Maritech, including the decommissioning liabilities associated with the oil and gas properties previously sold by Maritech (the “Legacy Liabilities”), subject to certain limited exceptions unrelated to the decommissioning liabilities. To the extent that Maritech or Orinoco fails to satisfy decommissioning liabilities associated with any of the Orinoco Lease Liabilities or the Legacy Liabilities, we may be required to satisfy such liabilities under third party indemnity agreements and corporate guarantees that we previously provided to the U.S. Department of the Interior and other parties, respectively.
Pursuant to a Bonding Agreement entered into as part of these transactions (the “Bonding Agreement”), Orinoco provided non-revocable performance bonds in an aggregate amount of $46.8 million to cover the performance by Orinoco and Maritech of the asset retirement obligations of Maritech (the “Initial Bonds”) and agreed to replace, within 90 days following the closing, the Initial Bonds with other non-revocable performance bonds, meeting certain requirements, in the aggregate sum of $47.0 million (collectively, the “Interim Replacement Bonds”). Orinoco further agreed to replace, within 180 days following the closing, the Interim Replacement Bonds with a maximum of three non-revocable performance bonds in the aggregate sum of $47.0 million, meeting certain requirements (the “Final Bonds”). Among the other requirements of the Final Bonds was that they must provide coverage for all of the asset retirement obligations of Maritech instead of only relating to specific properties. In the event Orinoco does not provide the Interim Replacement Bonds or the Final Bonds, Orinoco is required to make certain cash escrow payments to us.
The payment obligations of Orinoco under the Bonding Agreement were guaranteed by Thomas M. Clarke and Ana M. Clarke pursuant to a separate guaranty agreement (the “Clarke Bonding Guaranty Agreement”). Orinoco has not delivered such replacement bonds and neither it nor the Clarkes has made any of the agreed upon cash escrow payments and we filed a lawsuit against Orinoco and the Clarkes to enforce the terms of the Bonding Agreement and the Clarke Bonding Guaranty Agreement. A summary judgment was initially granted in favor of Orinoco and the Clarkes which dismissed our claims against Orinoco under the Bonding Agreement and against the Clarkes under the Clarke Bonding Guaranty Agreement. We filed an appeal and also asked the trial court to grant a new trial on the summary judgment or to modify the judgment because we believe this judgment should not have been granted. On November 5, 2019, the trial court signed an order granting our motion for new trial and vacating the prior order granting summary judgment for Orinoco and the Clarkes. The parties are awaiting direction from the court on a new scheduling order and/or trial setting. The Initial Bonds, which are non-revocable, remain in effect.
If we become liable in the future for any decommissioning liability associated with any property covered by either an Initial Bond or an Interim Replacement Bond while such bonds are outstanding and the payment made to us under such bond is not sufficient to satisfy such liability, the Bonding Agreement provides that Orinoco will pay us an amount equal to such deficiency and if Orinoco fails to pay any such amount, such amount must be paid by the Clarkes under the Clarke Bonding Guaranty Agreement. However, if the Final Bonds or the full amount of the escrowed cash have been provided, neither Orinoco nor the Clarkes would be liable to pay us for any such deficiency. Our financial condition and results of operations may be negatively affected if Orinoco is unable to cover any such deficiency or if we become liable for a significant portion of the decommissioning liabilities.
In early 2018, we also closed the sale of our Offshore Division to Epic Companies, LLC (“Epic Companies,” formerly known as Epic Offshore Specialty, LLC). Part of the consideration we received was a promissory note of Epic Companies in the original principal amount of $7.5 million (the “Epic Promissory Note”). At the end of August 2019, Epic Companies filed for bankruptcy and we recorded a reserve of $7.5 million for the full amount of the promissory note, including accrued interest, and certain other receivables in the amount of $1.5 million during the quarter ended September 30, 2019. The Epic Promissory Note became due on December 31, 2019 and neither Epic nor the Clarkes made payment. TETRA filed a lawsuit against the Clarkes on January 15, 2020 for breach of the promissory note guaranty agreement. In September 2020, the court granted TETRA’s Motion for Summary
Judgment and entered Final Judgment in our favor, dismissing counterclaims by the Clarkes and awarded TETRA $7.9 million in damages. The Clarkes have filed an appeal which we will defend. We cannot provide any assurance the Clarkes will pay the judgment or that they will not file for bankruptcy protection. If the Clarkes do file for bankruptcy protection, we likely would be unable to collect all, or even a significant portion of, the judgment owed to us.
See Note 3 - “Discontinued Operations” and Note 11 - “Acquisitions and Dispositions” for further discussion.
NOTE 13 — CAPITAL STOCK AND WARRANTS
Our Restated Certificate of Incorporation, as amended during 2017, authorizes us to issue 250,000,000 shares of common stock, par value $.01 per share, and 5,000,000 shares of preferred stock, par value $.01 per share. As of December 31, 2020, we had 125,976,071 shares of common stock outstanding, with 2,953,976 shares held in treasury, and no shares of preferred stock outstanding. The voting, dividend, and liquidation rights of the holders of common stock are subject to the rights of the holders of preferred stock. The holders of common stock are entitled to one vote for each share held. There is no cumulative voting. Dividends may be declared and paid on common stock as determined by our Board of Directors, subject to any preferential dividend rights of any then outstanding preferred stock.
Issuances of Common Stock. On February 28, 2018, we issued 7,772,021 shares of our common stock as part of the consideration paid for the acquisition of SwiftWater. For further discussion of the SwiftWater acquisition, see Note 11 - “Acquisitions and Dispositions”.
On December 14, 2016, we completed a firm commitment underwritten offering of 22.3 million shares of our common stock at a price to the public of $5.15 per share ($4.9183 per share net of underwriting discounts) and the Warrants to purchase 11.2 million shares of our common stock at an exercise price of $5.75 per share prior to the 60-month expiration date of the Warrants. The 22.3 million shares of our common stock issued and the Warrants to purchase 11.2 million shares of our common stock includes 2.9 million shares of our common stock and Warrants to acquire an additional 1.5 million shares of our common stock related to the exercise of an option granted to the underwriters. We utilized the net offering proceeds of $109.7 million to repay outstanding indebtedness and other offering expenses. As of December 31, 2020, all of the Warrants remain outstanding.
The Warrants were issued pursuant to a Warrant Agreement, dated December 14, 2016, and are exercisable immediately upon issuance and from time to time thereafter through and including the fifth year anniversary of the initial issuance date. At the request of a holder following a change of control, we or the successor entity will exchange such Warrant for consideration in accordance with a Black Scholes option pricing model in the form of, at our election, Rights (as defined in the Warrant Agreement) or cash. Similarly, within a period of time prior to the consummation of a change of control, we have the right to redeem all of the Warrants for cash in an amount determined in accordance with a Black-Scholes option pricing model.
The Warrants are accounted for as a derivative liability in accordance with ASC 815 “Derivatives and Hedging” and accordingly are carried at their fair value, with changes in fair value included in earnings in the period of change.
A summary of the activity of our common shares outstanding and treasury shares held for the three year period ending December 31, 2020, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Shares Outstanding
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
At beginning of period
|
|
125,481,163
|
|
|
125,737,565
|
|
|
115,877,704
|
|
|
Exercise of common stock options, net
|
|
—
|
|
|
—
|
|
|
65,524
|
|
|
Grants of restricted stock, net (1)
|
|
494,908
|
|
|
(256,402)
|
|
|
2,022,316
|
|
|
Issuance of common stock
|
|
—
|
|
|
—
|
|
|
7,772,021
|
|
|
At end of period
|
|
125,976,071
|
|
|
125,481,163
|
|
|
125,737,565
|
|
(1)Prior to 2019, we primarily granted restricted stock awards, which immediately impacted common shares outstanding. In contrast, during 2020 and 2019, we primarily granted restricted stock units which do not impact common shares outstanding until vesting. Vesting for restricted stock units began in 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury Shares Held
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
At beginning of period
|
|
2,823,191
|
|
|
2,717,569
|
|
|
2,638,093
|
|
|
|
|
|
|
|
|
|
|
Shares received upon vesting of restricted stock, net
|
|
130,785
|
|
|
105,622
|
|
|
79,476
|
|
|
At end of period
|
|
2,953,976
|
|
|
2,823,191
|
|
|
2,717,569
|
|
Our Board of Directors is empowered, without approval of the stockholders, to cause shares of preferred stock to be issued in one or more series and to establish the number of shares to be included in each such series and the rights, powers, preferences, and limitations of each series. Because the Board of Directors has the power to establish the preferences and rights of each series, it may afford the holders of any series of preferred stock preferences, powers and rights, voting or otherwise, senior to the rights of holders of common stock. The issuance of the preferred stock could have the effect of delaying or preventing a change in control of the Company.
Upon our dissolution or liquidation, whether voluntary or involuntary, holders of our common stock will be entitled to receive all of our assets available for distribution to our stockholders, subject to any preferential rights of any then outstanding preferred stock.
NOTE 14 — EQUITY-BASED COMPENSATION AND OTHER
Equity-Based Compensation
We have various equity incentive compensation plans that provide for the granting of restricted common stock, options for the purchase of our common stock, and other performance-based, equity-based compensation awards to our executive officers, key employees, nonexecutive officers, and directors. Stock options are exercisable for periods of up to ten years. Compensation cost for all share-based payments is based on the grant date fair value and is recognized in earnings over the requisite service period. Total equity-based compensation expense before tax for the three years ended December 31, 2020, 2019, and 2018, was $5.5 million, $5.8 million, and $6.7 million, respectively, and is included in general and administrative expense.
Stock Incentive Plans
In May 2007, our stockholders approved the adoption of the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan. In May 2008, our stockholders approved the adoption of the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan, which among other changes, resulted in an increase in the maximum number of shares authorized for issuance. In May 2010, our stockholders approved further amendments to the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (renamed as the 2007 Long Term Incentive Compensation Plan) which, among other changes, resulted in an additional increase in the maximum number of shares authorized for issuance. Pursuant to the 2007 Long Term Incentive Compensation Plan, we are authorized to grant up to 5,590,000 shares in the form of stock options (including incentive stock options and nonqualified stock options); restricted stock; bonus stock; stock appreciation rights; and performance awards to employees, and non-employee directors. As of February 2017, no further awards may be granted under the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan.
In May 2011, our stockholders approved the adoption of the TETRA Technologies, Inc. 2011 Long Term Incentive Compensation Plan. Pursuant to this plan, we were authorized to grant up to 2,200,000 shares in the form of stock options, restricted stock, bonus stock, stock appreciation rights, and performance awards to employees, and non-employee directors. On May 3, 2013, shareholders approved the TETRA Technologies, Inc. 2011 Long Term Incentive Compensation Plan that, among other things, increased the number of authorized shares to 5,600,000. On May 3, 2016, shareholders approved the TETRA Technologies, Inc. Third Amended and Restated 2011 Long Term Incentive Compensation Plan which, among other things, increased the number of authorized shares to 11,000,000. As of May 2018, no further awards may be granted under the TETRA Technologies, Inc. Third Amended and Restated 2011 Long Term Incentive Compensation Plan.
In February 2018, the board of directors adopted the 2018 Inducement Restricted Stock Plan (“2018 Inducement Plan”). The 2018 Inducement Plan provides for grants of restricted stock up to a plan maximum of 1,000,000 shares.
In May 2018, our stockholders approved the adoption of the TETRA Technologies, Inc. 2018 Equity Incentive Plan (“2018 Equity Plan”). Pursuant to this plan, we were authorized to grant up to 6,635,000 shares in the form of stock options, restricted stock, restricted stock units, bonus stock, stock appreciation rights, performance units, performance awards, other stock-based awards and cash-based awards to employees and non-employee directors.
In May 2018, our stockholders approved the adoption of the TETRA Technologies, Inc. 2018 Non-Employee Director Equity Incentive Plan (“2018 Director Plan”). Pursuant to this plan, we were authorized to grant up to 335,000 shares in the form of nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, other stock‑based awards and cash-based awards to non-employee directors.
Stock Options
We did not grant any stock options during the year ended December 31, 2020. The weighted average fair value of options granted during the years ended December 31, 2019, and 2018, was $0.76 and $1.88, respectively, using the Black-Scholes option valuation model with the following weighted average assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2019
|
|
2018
|
|
Expected stock price volatility
|
|
61
|
%
|
|
57
|
%
|
|
Expected life of options
|
|
4.4 years
|
|
4.5 years
|
|
Risk-free interest rate
|
|
2.3
|
%
|
|
2.6
|
%
|
|
Expected dividend yield
|
|
—
|
|
|
—
|
|
The risk-free interest rate is based on the U.S. Treasury yield curve in effect on the grant date for a period commensurate with the estimated expected life of the stock options. Expected volatility is based on the historical volatility of our stock over the period commensurate with the expected life of the stock options and other factors. The dividend yield is based on the current annualized dividend rate in effect during the quarter in which the grant was made. At the time of the stock option grants during each of the years ended December 31, 2019 and 2018, we had not historically paid any dividends and did not expect to pay any dividends during the expected life of the stock options.
The following is a summary of stock option activity for the years ended December 31, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares Under Option
|
|
Weighted Average
Option Price
Per Share
|
|
Weighted-Average Remaining Contractual Life
|
|
Aggregate Intrinsic Value
(in thousands)
|
|
|
|
(In Thousands)
|
|
|
|
|
|
|
|
Outstanding at January 1, 2020
|
|
3,686
|
|
|
$
|
6.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options canceled
|
|
(302)
|
|
|
6.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options expired
|
|
(176)
|
|
|
10.27
|
|
|
|
|
|
|
Outstanding at December 31, 2020
|
|
3,208
|
|
|
6.73
|
|
|
4.8 years
|
|
$
|
—
|
|
|
Expected to vest at December 31, 2020
|
|
3,208
|
|
|
6.73
|
|
|
4.8 years
|
|
—
|
|
|
Exercisable at December 31, 2020
|
|
3,171
|
|
|
6.76
|
|
|
4.8 years
|
|
—
|
|
|
Available for grant, end of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares Under Option
|
|
Weighted Average
Option Price
Per Share
|
|
Weighted-Average Remaining Contractual Life
|
|
Aggregate Intrinsic Value
(in thousands)
|
|
|
|
(In Thousands)
|
|
|
|
|
|
|
|
Outstanding at January 1, 2019
|
|
4,480
|
|
|
$
|
6.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options granted
|
|
72
|
|
|
4.51
|
|
|
|
|
|
|
Options canceled
|
|
(426)
|
|
|
6.85
|
|
|
|
|
|
|
Options exercised
|
|
—
|
|
|
—
|
|
|
|
|
|
|
Options expired
|
|
(440)
|
|
|
3.98
|
|
|
|
|
|
|
Outstanding at December 31, 2019
|
|
3,686
|
|
|
6.90
|
|
|
5.5 years
|
|
$
|
—
|
|
|
Expected to vest at December 31, 2019
|
|
3,686
|
|
|
6.90
|
|
|
5.5 years
|
|
—
|
|
|
Exercisable at December 31, 2019
|
|
3,369
|
|
|
7.18
|
|
|
5.3 years
|
|
—
|
|
Intrinsic value is the difference between the market value of our stock option multiplied by the number of stock options outstanding for those stock options where the market value exceeds their exercise price. The total intrinsic value of stock options exercised during the year ended December 31, 2018, was approximately $0.1 million. There were no options exercised during the years ended December 31, 2020 and 2019 . At December 31, 2020, total unrecognized compensation cost related to unvested stock options is not significant.
Restricted Stock
Restricted stock awards and restricted stock units are periodically granted to key employees, including grants for employment inducements, as well as to members of our Board of Directors. These awards historically have provided for vesting periods of three years. Non-employee director grants vest in full before the first anniversary of the grant. Upon vesting of restricted stock awards, shares are issued to award recipients. Restricted stock units may be settled in cash or shares at vest, as determined by the Compensation Committee or the Non-Executive Award Committee, as applicable. The following is a summary of activity for our outstanding restricted stock for the year ended December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Weighted Average
Grant Date Fair
Value Per Share
|
|
|
|
(In Thousands)
|
|
|
|
Non-vested restricted stock outstanding at December 31, 2019
|
|
3,577
|
|
|
$
|
2.85
|
|
|
Granted
|
|
1,958
|
|
|
1.39
|
|
|
Vested
|
|
(1,577)
|
|
|
2.87
|
|
|
Canceled/Forfeited
|
|
(225)
|
|
|
2.22
|
|
|
Non-vested restricted stock outstanding at December 31, 2020
|
|
3,733
|
|
|
2.11
|
|
Total compensation cost recognized for restricted stock was $5.1 million, $4.8 million, and $4.9 million for the years ended December 31, 2020, 2019, and 2018, respectively. Total unrecognized compensation cost at December 31, 2020, related to restricted stock is approximately $3.4 million which is expected to be recognized over a weighted-average remaining amortization period of 1.6 years. During the years ended December 31, 2020, 2019, and 2018, the total fair value of shares vested was $4.5 million, $4.0 million and $3.2 million, respectively.
During 2020, 2019, and 2018, we received 130,785, 105,622 and 79,476 shares, respectively, of our common stock related to the vesting of certain employee restricted stock. Such surrendered shares received by us are included in treasury stock. At December 31, 2020, net of options previously exercised pursuant to our various equity compensation plans, we have a maximum of 2,771,052 shares of common stock issuable pursuant to awards previously granted and outstanding and awards authorized to be granted in the future.
401(k) Plan
We have a 401(k) retirement plan (the “Plan”) that covers substantially all employees and entitles them to contribute up to 75% of their annual compensation, subject to maximum limitations imposed by the Internal
Revenue Code. Effective October 1, 2018, enhancements were made to the Plan, including changing the employer match to 50% of each employee’s contribution up to 8%. Participants will be 100% vested in employer match contributions after 3 years of service, instead of after 5 years of service. In addition, we can make discretionary contributions which are allocable to participants in accordance with the Plan. During 2020, we suspended 401(k) matching for our employees due to the COVID pandemic and market conditions. Total expense related to our 401(k) plan was $1.5 million, $5.1 million, and $3.8 million for the years ended December 31, 2020, 2019, and 2018, respectively.
Deferred Compensation Plan
We provide our officers, directors, and certain key employees with the opportunity to participate in an unfunded, deferred compensation program. There were 16 participants in the program at December 31, 2020. Under the program, participants may defer up to 100% of their yearly total cash compensation. The amounts deferred remain our sole property, and we use a portion of the proceeds to purchase life insurance policies on the lives of certain of the participants. The insurance policies, which also remain our sole property, are payable to us upon the death of the insured. We separately contract with the participant to pay to the participant the amount of deferred compensation, as adjusted for gains or losses, invested in participant-selected investment funds. Participants may elect to receive deferrals and earnings at termination, death, or at a specified future date while still employed. Distributions while employed must be at least three years after the deferral election. The program is not qualified under Section 401 of the Internal Revenue Code. At December 31, 2020, the amounts payable under the plan approximated the value of the corresponding assets we owned.
NOTE 15 — FAIR VALUE MEASUREMENTS
Fair value is defined as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date” within an entity’s principal market, if any. The principal market is the market in which the reporting entity would sell the asset or transfer the liability with the greatest volume and level of activity, regardless of whether it is the market in which the entity will ultimately transact for a particular asset or liability or if a different market is potentially more advantageous. Accordingly, this exit price concept may result in a fair value that may differ from the transaction price or market price of the asset or liability.
Under U.S. GAAP, the fair value hierarchy prioritizes inputs to valuation techniques used to measure fair value. Fair value measurements should maximize the use of observable inputs and minimize the use of unobservable inputs, where possible. Observable inputs are developed based on market data obtained from sources independent of the reporting entity. Unobservable inputs may be needed to measure fair value in situations where there is little or no market activity for the asset or liability at the measurement date and are developed based on the best information available in the circumstances, which could include the reporting entity’s own judgments about the assumptions market participants would utilize in pricing the asset or liability.
Financial Instruments
Mineral Resources Arrangements
The Company receives cash and stock of Standard Lithium (TSXV: SLL) under the terms of its arrangements. Our investment in Standard Lithium is recorded in other assets on our consolidated balance sheets based on the quoted market stock price (a Level 2 fair value measurement). The stock component of consideration received is initially recorded as unearned income based on the quoted market price at the time the stock is received, then recognized in income over the contract term. The unearned income associated with the stock component of this agreement is not significant as of December 31, 2020 or 2019. Changes in the value of stock are recorded in other income (expense) in our consolidated statements of operations.
Warrants
The Warrants are valued by using a Black Scholes option valuation model that includes implied volatility of the trading price (a Level 3 fair value measurement). The fair value of the Warrants liability is increased by, among other factors, increases in our common stock price and increases in the volatility of our common stock price. Changes in the fair value of the Warrants will increase or decrease the associated liability and result in future adjustments to earnings for the associated valuation losses (gains).
Contingent Consideration
The February 2018 acquisition of SwiftWater resulted in a contingent purchase price consideration that was payable in two tranches based on 2018 and 2019 results. During the year ended December 31, 2019, the sellers received a payment of $10.0 million based on 2018 performance. Changes to the estimated contingent purchase price consideration for performance during 2019 resulted in $1.0 million being credited to other (income) expense, net, during the year ended December 31, 2019. Also during the year ended December 31, 2019, in accordance with the December 2018 purchase of JRGO, the sellers were paid contingent consideration of $1.4 million based on performance during the fourth quarter of 2018. As of December 31, 2019, there were no remaining contingent purchase price consideration liabilities for either acquisition.
Derivative Contracts
We are exposed to financial and market risks that affect our businesses. We have concentrations of credit risk as a result of trade receivables owed to us by companies in the energy industry. We have currency exchange rate risk exposure related to transactions denominated in foreign currencies as well as to investments in certain of our international operations. As a result of our variable rate debt facilities, we face market risk exposure related to changes in applicable interest rates. Our financial risk management activities may at times involve, among other measures, the use of derivative financial instruments, such as swap and collar agreements, to hedge the impact of market price risk exposures.
We entered into, and we may in the future enter into, short-term foreign currency forward derivative contracts with third parties as part of a program designed to mitigate the currency exchange rate risk exposure on selected transactions of certain foreign subsidiaries. Although contracts pursuant to this program will serve as an economic hedge of the cash flow of our currency exchange risk exposure, they are not formally designated as hedge contracts or qualify for hedge accounting treatment. Accordingly, any change in the fair value of these derivative instruments during a period will be included in the determination of earnings for that period. The fair values of foreign currency derivative instruments are based on quoted market values (a Level 2 fair value measurement). The fair values of our foreign currency derivative instruments as of December 31, 2020 and 2019 was insignificant. During the years ended December 31, 2020, 2019, and 2018, we recognized approximately $0.2 million, $1.5 million and $(0.4) million of net (gains) losses, respectively, reflected in other (income) expense, net, associated with our foreign currency derivative program.
A summary of significant recurring fair value measurements by valuation hierarchy as of December 31, 2020 and December 31, 2019, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
Total as of
|
|
Quoted Prices
in Active
Markets for
Identical
Assets
or Liabilities
|
|
Significant
Other
Observable
Inputs
|
|
Significant
Unobservable
Inputs
|
|
Description
|
|
Dec 31, 2020
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
|
|
(In Thousands)
|
|
Investment in Standard Lithium
|
|
$
|
2,675
|
|
|
—
|
|
|
2,675
|
|
|
—
|
|
|
Warrants liability
|
|
(198)
|
|
|
—
|
|
|
—
|
|
|
(198)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
Total as of
|
|
Quoted Prices
in Active
Markets for
Identical
Assets
or Liabilities
|
|
Significant
Other
Observable
Inputs
|
|
Significant
Unobservable
Inputs
|
|
Description
|
|
Dec 31, 2019
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
|
|
(In Thousands)
|
|
Investment in Standard Lithium
|
|
$
|
520
|
|
|
$
|
—
|
|
|
$
|
520
|
|
|
$
|
—
|
|
|
Warrants liability
|
|
(449)
|
|
|
—
|
|
|
—
|
|
|
(449)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During 2019, our Completion Fluids & Products and Water & Flowback Services Divisions each recorded certain long-lived tangible asset impairments. The Completion Fluids & Products Division recorded an impairment of $91.6 million related to our El Dorado, Arkansas calcium chloride production plant facility assets primarily due to a reduction in the cost of raw materials for certain of our other chemical production plants, following the execution of a long-term raw material supply agreement during the fourth quarter of 2019. Also in 2019, our Water & Flowback Services Division recorded goodwill impairment of $25.8 million.
The fair values used in these impairment calculations were estimated based on discounted estimated future cash flows, including projected future cash flows and/or estimated replacement costs, or a fair value in-exchange assumption, which are based on significant unobservable inputs (Level 3) in accordance with the fair value hierarchy. For further discussion, see Note 6 - “Impairments and Other Charges”.
A summary of these nonrecurring fair value measurements during the year ended December 31, 2019, using the fair value hierarchy, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
Description
|
|
Fair Value
|
|
Quoted Prices in Active Markets for Identical Assets
or Liabilities
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Year-to-Date
Impairment Losses
|
|
|
|
(In Thousands)
|
|
Completion Fluids & Products production facility
|
|
$
|
9,459
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,459
|
|
|
$
|
91,606
|
|
|
Water & Flowback Services goodwill
|
|
$
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25,784
|
|
|
Water & Flowback Services equipment
|
|
$
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
284
|
|
|
Total
|
|
$
|
9,459
|
|
|
|
|
|
|
|
|
$
|
117,674
|
|
Other
The fair values of cash, restricted cash, accounts receivable, accounts payable, accrued liabilities, short-term borrowings and long-term debt pursuant to TETRA's ABL Credit Agreement and Term Credit Agreement approximate their carrying amounts.
NOTE 16 — INCOME TAXES
The income tax provision attributable to continuing operations for the years ended December 31, 2020, 2019, and 2018, consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
(In Thousands)
|
|
Current
|
|
|
|
|
|
|
|
Federal
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
State
|
|
191
|
|
|
400
|
|
|
360
|
|
|
Foreign
|
|
1,598
|
|
|
2,837
|
|
|
3,742
|
|
|
|
|
1,789
|
|
|
3,237
|
|
|
4,102
|
|
|
Deferred
|
|
|
|
|
|
|
|
Federal
|
|
(175)
|
|
|
(161)
|
|
|
(151)
|
|
|
State
|
|
(125)
|
|
|
(395)
|
|
|
(149)
|
|
|
Foreign
|
|
269
|
|
|
130
|
|
|
(118)
|
|
|
|
|
(31)
|
|
|
(426)
|
|
|
(418)
|
|
|
Total tax provision
|
|
$
|
1,758
|
|
|
$
|
2,811
|
|
|
$
|
3,684
|
|
A reconciliation of the provision (benefit) for income taxes attributable to continuing operations, computed by applying the federal statutory rate to income (loss) before income taxes and the reported income taxes, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
(In Thousands)
|
|
Income tax provision (benefit) computed at statutory federal income tax rates
|
|
$
|
(5,268)
|
|
|
$
|
(26,903)
|
|
|
$
|
(552)
|
|
|
State income taxes (net of federal benefit)
|
|
(2,124)
|
|
|
(2,388)
|
|
|
(1,345)
|
|
|
|
|
|
|
|
|
|
|
Impact of international operations
|
|
4,036
|
|
|
672
|
|
|
13,790
|
|
|
Impact of U.S. tax law change
|
|
—
|
|
|
—
|
|
|
(2,510)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valuation allowance
|
|
4,598
|
|
|
30,640
|
|
|
(8,115)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
516
|
|
|
790
|
|
|
2,416
|
|
|
Total tax provision
|
|
$
|
1,758
|
|
|
$
|
2,811
|
|
|
$
|
3,684
|
|
Income (loss) before taxes and discontinued operations includes the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
(In Thousands)
|
|
Domestic
|
|
$
|
(25,929)
|
|
|
$
|
(135,668)
|
|
|
$
|
(8,143)
|
|
|
International
|
|
843
|
|
|
7,559
|
|
|
5,515
|
|
|
Total
|
|
$
|
(25,086)
|
|
|
$
|
(128,109)
|
|
|
$
|
(2,628)
|
|
A reconciliation of the beginning and ending amount of our gross unrecognized tax benefit is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
(In Thousands)
|
|
Gross unrecognized tax benefits at beginning of period
|
|
$
|
137
|
|
|
$
|
328
|
|
|
$
|
530
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lapse in statute of limitations
|
|
(120)
|
|
|
(191)
|
|
|
(202)
|
|
|
Gross unrecognized tax benefits at end of period
|
|
$
|
17
|
|
|
$
|
137
|
|
|
$
|
328
|
|
We recognize interest and penalties related to uncertain tax positions in income tax expense. During the years ended December 31, 2020, 2019, and 2018, we recognized $(0.2) million, $(0.3) million, and $(0.2) million, respectively, of interest and penalties. As of December 31, 2020 and 2019, we had less than $0.1 million and $0.2 million, respectively, of accrued potential interest and penalties associated with uncertain tax positions. The total amount of unrecognized tax benefits that would affect our effective tax rate if recognized was less than $0.1 million and $0.4 million as of December 31, 2020 and 2019, respectively. We do not expect a significant change to the unrecognized tax benefits during the next twelve months.
We file tax returns in the U.S. and in various state, local, and non-U.S. jurisdictions. The following table summarizes the earliest tax years that remain subject to examination by taxing authorities in any major jurisdiction in which we operate:
|
|
|
|
|
|
|
|
Jurisdiction
|
Earliest Open Tax Period
|
|
United States – Federal
|
2012
|
|
United States – State and Local
|
2002
|
|
Non-U.S. jurisdictions
|
2011
|
We use the liability method for reporting income taxes, under which current and deferred tax assets and liabilities are recorded in accordance with enacted tax laws and rates. Under this method, at the end of each period, the amounts of deferred tax assets and liabilities are determined using the tax rate expected to be in effect when the taxes are actually paid or recovered. We establish a valuation allowance to reduce the deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. We considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed for some portion or all of our deferred tax assets. In determining the need for a valuation allowance on our deferred tax assets we placed greater weight on recent and objectively verifiable current information, as compared to more forward-looking information that is used in valuating other assets on the balance sheet. While we have considered taxable income in prior carryback years, future reversals of existing taxable temporary differences, future taxable income, and tax planning strategies in assessing the need for the valuation allowance, there can be no guarantee that we will be able to realize our net deferred tax assets. Significant components of our deferred tax assets and liabilities as of December 31, 2020 and 2019 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2020
|
|
2019
|
|
|
|
(In Thousands)
|
|
Net operating losses
|
|
$
|
104,478
|
|
|
$
|
103,834
|
|
|
|
|
|
|
|
|
Accruals
|
|
16,515
|
|
|
20,674
|
|
|
|
|
|
|
|
|
Depreciation and amortization for book in excess of tax expense
|
|
12,608
|
|
|
14,262
|
|
|
Investment in Partnership
|
|
23,344
|
|
|
—
|
|
|
All other
|
|
12,743
|
|
|
16,583
|
|
|
Total deferred tax assets
|
|
169,688
|
|
|
155,353
|
|
|
Valuation allowance
|
|
(146,678)
|
|
|
(123,808)
|
|
|
Net deferred tax assets
|
|
$
|
23,010
|
|
|
$
|
31,545
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2020
|
|
2019
|
|
|
|
(In Thousands)
|
|
Right of use asset
|
|
$
|
7,808
|
|
|
$
|
9,091
|
|
|
Depreciation and amortization for tax in excess of book expense
|
|
15,402
|
|
|
18,596
|
|
|
All other
|
|
1,690
|
|
|
5,635
|
|
|
Total deferred tax liability
|
|
24,900
|
|
|
33,322
|
|
|
Net deferred tax liability
|
|
$
|
1,890
|
|
|
$
|
1,777
|
|
We believe that it is more likely than not we will not realize all the tax benefits of the deferred tax assets within the allowable carryforward period. Therefore, an appropriate valuation allowance has been provided. The valuation allowance as of December 31, 2020 and 2019 primarily relates to federal deferred tax assets. The $22.9 million increase in the valuation allowance during the year ended December 31, 2020 was primarily due to the increase in Federal deferred tax assets, the majority of which is related to the sale of our partnership interest in CCLP in January 2021 as discussed in Note 18 - “Subsequent Event.” Entering into the GP Sale in January 2021 resulted in the recognition of temporary deferred assets associated with the outside basis difference of some of our subsidiaries at December 31, 2020. These temporary differences are fully offset by an increase to the valuation allowance.
At December 31, 2020, we had federal, state, and foreign net operating loss carryforwards/carrybacks equal to approximately $80.0 million, $11.4 million, and $13.0 million, respectively. In those countries and states in which net operating losses are subject to an expiration period, our loss carryforwards, if not utilized, will expire at various dates from 2021 through 2040. Utilization of the net operating loss and credit carryforwards may be subject to a significant annual limitation due to ownership changes that have occurred previously or could occur in the future provided by Section 382 of the Internal Revenue Code.
NOTE 17 — INDUSTRY SEGMENTS AND GEOGRAPHIC INFORMATION
We manage our operations through two divisions: Completion Fluids & Products and Water & Flowback Services. We generally evaluate the performance of and allocate resources to our segments based on profit or loss from their operations before income taxes and nonrecurring charges, return on investment, and other criteria. Transfers between segments and geographic areas are priced at the estimated fair value of the products or services as negotiated between the operating units. “Corporate overhead” includes corporate general and administrative expenses, corporate depreciation and amortization, interest income and expense, and other income and expense.
Summarized financial information concerning the business segments is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
(In Thousands)
|
|
Revenues from external customers
|
|
|
|
|
|
|
|
Product sales
|
|
|
|
|
|
|
|
Completion Fluids & Products Division
|
|
$
|
229,809
|
|
|
$
|
258,632
|
|
|
$
|
242,412
|
|
|
Water & Flowback Services Division
|
|
2,912
|
|
|
921
|
|
|
1,961
|
|
|
|
|
|
|
|
|
|
|
Consolidated
|
|
$
|
232,721
|
|
|
$
|
259,553
|
|
|
$
|
244,373
|
|
|
|
|
|
|
|
|
|
|
Services
|
|
|
|
|
|
|
|
Completion Fluids & Products Division
|
|
$
|
12,852
|
|
|
$
|
20,623
|
|
|
$
|
15,002
|
|
|
Water & Flowback Services Division
|
|
132,142
|
|
|
281,065
|
|
|
300,727
|
|
|
|
|
|
|
|
|
|
|
Consolidated
|
|
$
|
144,994
|
|
|
$
|
301,688
|
|
|
$
|
315,729
|
|
|
|
|
|
|
|
|
|
|
Interdivision revenues
|
|
|
|
|
|
|
|
Completion Fluids & Products Division
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(6)
|
|
|
Water & Flowback Services Division
|
|
—
|
|
|
—
|
|
|
384
|
|
|
|
|
|
|
|
|
|
|
Interdivision eliminations
|
|
—
|
|
|
—
|
|
|
(378)
|
|
|
Consolidated
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
|
|
|
|
|
Completion Fluids & Products Division
|
|
$
|
242,661
|
|
|
$
|
279,255
|
|
|
$
|
257,408
|
|
|
Water & Flowback Services Division
|
|
135,054
|
|
|
281,986
|
|
|
303,072
|
|
|
|
|
|
|
|
|
|
|
Interdivision eliminations
|
|
—
|
|
|
—
|
|
|
(378)
|
|
|
Consolidated
|
|
$
|
377,715
|
|
|
$
|
561,241
|
|
|
$
|
560,102
|
|
|
|
|
|
|
|
|
|
|
Depreciation, amortization, and accretion
|
|
|
|
|
|
|
|
Completion Fluids & Products
|
|
$
|
7,581
|
|
|
$
|
13,518
|
|
|
$
|
15,345
|
|
|
Water & Flowback Services
|
|
29,913
|
|
|
33,410
|
|
|
28,422
|
|
|
Corporate
|
|
720
|
|
|
635
|
|
|
658
|
|
|
Consolidated
|
|
$
|
38,214
|
|
|
$
|
47,563
|
|
|
$
|
44,425
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
|
|
|
|
|
Completion Fluids & Products
|
|
$
|
73
|
|
|
$
|
68
|
|
|
$
|
179
|
|
|
Water & Flowback Services
|
|
4
|
|
|
7
|
|
|
5
|
|
|
Corporate
|
|
19,249
|
|
|
21,733
|
|
|
19,565
|
|
|
Consolidated interest expense
|
|
19,326
|
|
|
$
|
21,808
|
|
|
$
|
19,749
|
|
|
Consolidated interest income
|
|
(400)
|
|
|
(552)
|
|
|
(708)
|
|
|
Consolidated interest expense, net
|
|
$
|
18,926
|
|
|
$
|
21,256
|
|
|
$
|
19,041
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before taxes and discontinued operations
|
|
|
|
|
|
|
|
Completion Fluids & Products
|
|
$
|
55,334
|
|
|
$
|
(33,969)
|
|
|
$
|
30,623
|
|
|
Water & Flowback Services
|
|
(21,850)
|
|
|
(21,173)
|
|
|
28,712
|
|
|
Interdivision eliminations
|
|
12
|
|
|
14
|
|
|
11
|
|
|
Corporate(1)
|
|
(58,582)
|
|
|
(72,981)
|
|
|
(61,974)
|
|
|
Consolidated
|
|
$
|
(25,086)
|
|
|
$
|
(128,109)
|
|
|
$
|
(2,628)
|
|
(1) Amounts reflected include the following general corporate expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
(In Thousands)
|
|
General and administrative expense
|
|
$
|
36,201
|
|
|
$
|
51,466
|
|
|
$
|
50,431
|
|
|
Depreciation and amortization
|
|
818
|
|
|
631
|
|
|
658
|
|
|
Interest expense, net
|
|
20,727
|
|
|
21,977
|
|
|
19,640
|
|
|
Warrants fair value adjustment (income) expense
|
|
(251)
|
|
|
(1,624)
|
|
|
(11,128)
|
|
|
Other general corporate (income) expense, net
|
|
1,087
|
|
|
531
|
|
|
2,373
|
|
|
Total
|
|
$
|
58,582
|
|
|
$
|
72,981
|
|
|
$
|
61,974
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
(In Thousands)
|
|
Total assets
|
|
|
|
|
|
|
Completion Fluids & Products
|
|
|
$
|
218,952
|
|
|
$
|
236,420
|
|
|
Water & Flowback Services
|
|
|
136,511
|
|
|
180,765
|
|
|
Corporate, other and eliminations
|
|
|
67,370
|
|
|
32,038
|
|
|
Assets of discontinued operations
|
|
|
710,006
|
|
|
822,699
|
|
|
Consolidated
|
|
|
$
|
1,132,839
|
|
|
$
|
1,271,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
(In Thousands)
|
|
Capital expenditures
|
|
|
|
|
|
|
|
Completion Fluids & Products
|
|
$
|
4,016
|
|
|
$
|
7,140
|
|
|
$
|
5,259
|
|
|
Water & Flowback Services
|
|
9,651
|
|
|
24,340
|
|
|
30,175
|
|
|
Corporate
|
|
1,023
|
|
|
1,033
|
|
|
809
|
|
|
Discontinued operations (2)
|
|
14,696
|
|
|
75,760
|
|
|
105,688
|
|
|
Consolidated
|
|
$
|
29,386
|
|
|
$
|
108,273
|
|
|
$
|
141,931
|
|
(2) Amounts presented are net of cost of equipment sold, including $12.7 million during 2020, $6.5 million during 2019 and $10.0 million during 2018 for our former Compression Division.
Summarized financial information concerning the geographic areas of our customers and in which we operate at December 31, 2020, 2019, and 2018, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
(In Thousands)
|
|
Revenues from external customers
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
225,835
|
|
|
$
|
411,284
|
|
|
$
|
390,403
|
|
|
Canada and Mexico
|
|
1,347
|
|
|
6,616
|
|
|
17,575
|
|
|
South America
|
|
11,583
|
|
|
13,188
|
|
|
16,067
|
|
|
Europe
|
|
90,303
|
|
|
93,327
|
|
|
91,997
|
|
|
Africa
|
|
8,128
|
|
|
16,874
|
|
|
12,039
|
|
|
Middle East, Asia and other
|
|
40,519
|
|
|
19,952
|
|
|
32,021
|
|
|
Total
|
|
$
|
377,715
|
|
|
$
|
561,241
|
|
|
$
|
560,102
|
|
|
Transfers between geographic areas:
|
|
|
|
|
|
|
|
Europe
|
|
848
|
|
|
1,802
|
|
|
3,157
|
|
|
Eliminations
|
|
(848)
|
|
|
(1,802)
|
|
|
(3,157)
|
|
|
Total revenues
|
|
$
|
377,715
|
|
|
$
|
561,241
|
|
|
$
|
560,102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2020
|
|
2019
|
|
|
|
|
(In Thousands)
|
|
Identifiable assets
|
|
|
|
|
|
|
U.S.
|
|
$
|
285,765
|
|
|
$
|
338,054
|
|
|
|
Canada and Mexico
|
|
6,452
|
|
|
9,216
|
|
|
|
South America
|
|
10,388
|
|
|
13,632
|
|
|
|
Europe
|
|
85,733
|
|
|
62,684
|
|
|
|
Africa
|
|
9,195
|
|
|
10,812
|
|
|
|
Middle East, Asia and other
|
|
25,300
|
|
|
14,825
|
|
|
|
Assets of discontinued operations
|
|
710,006
|
|
|
822,699
|
|
|
|
Total identifiable assets
|
|
$
|
1,132,839
|
|
|
$
|
1,271,922
|
|
|
During each of the two years ended December 31, 2020 and 2018, no single customer accounted for more than 10% of our consolidated revenues. One customer provided more than 10% of our total consolidated revenues during the year ended December 31, 2019. As of December 31, 2020 and 2019, no receivables from individual customers represented 10% or more of our consolidated trade accounts receivables net of allowance for doubtful accounts.
NOTE 18 — SUBSEQUENT EVENT
The Company has evaluated subsequent events through the filing of this Annual Report on Form 10-K, and determined that there have been no events that have occurred that would require adjustments to our disclosures in the consolidated financial statements except for the transaction described below.
On January 29, 2021, we entered into the Purchase and Sale Agreement with Spartan pursuant to which we sold the general partner of CCLP, including the IDRs and approximately 23.1% of the outstanding limited partner interests in CCLP, in exchange for combination of $13.4 million in cash paid at closing, $0.5 million in cash payable on the six-month anniversary of the closing and $3.1 million in contingent consideration in the form of cash and/or CCLP common units if CCLP achieves certain financial targets on or before December 31, 2022. As a result of these transactions, TETRA will not consolidate CCLP beginning in the first quarter of 2021 and TETRA is expected to report an accounting gain of approximately $125.0 million in the first quarter of 2021. Additionally, our former Compression division, including CCLP’s operations, are now included in discontinued operations. See Note 3 - “Discontinued Operations”. Following the transaction, TETRA owns 5.2 million common units of CCLP. TETRA will also continue to provide back-office support to CCLP under a Transition Services Agreement for a period of time until CCLP has completed a full separation from TETRA’s back-office support functions.