Form: 10-K

Annual report pursuant to Section 13 and 15(d)

February 23, 2023

0001680247falseFY2022truehttp://fasb.org/us-gaap/2022#ServiceMemberhttp://fasb.org/us-gaap/2022#ServiceMemberhttp://fasb.org/us-gaap/2022#ServiceMemberhttp://fasb.org/us-gaap/2022#ServiceMemberhttp://fasb.org/us-gaap/2022#ServiceMemberhttp://fasb.org/us-gaap/2022#ServiceMemberP1Y0M0DP2YP3YP1Y00016802472022-01-012022-12-310001680247us-gaap:CommonClassAMember2022-01-012022-12-310001680247pump:PreferredStockPurchaseRightsMember2022-01-012022-12-3100016802472022-06-30iso4217:USD00016802472023-02-20xbrli:shares00016802472022-12-3100016802472021-12-31iso4217:USDxbrli:shares00016802472021-01-012021-12-3100016802472020-01-012020-12-310001680247us-gaap:CommonStockMember2019-12-310001680247us-gaap:AdditionalPaidInCapitalMember2019-12-310001680247us-gaap:RetainedEarningsMember2019-12-3100016802472019-12-310001680247us-gaap:AdditionalPaidInCapitalMember2020-01-012020-12-310001680247us-gaap:CommonStockMember2020-01-012020-12-310001680247us-gaap:RetainedEarningsMember2020-01-012020-12-310001680247us-gaap:CommonStockMember2020-12-310001680247us-gaap:AdditionalPaidInCapitalMember2020-12-310001680247us-gaap:RetainedEarningsMember2020-12-3100016802472020-12-310001680247us-gaap:AdditionalPaidInCapitalMember2021-01-012021-12-310001680247us-gaap:CommonStockMember2021-01-012021-12-310001680247us-gaap:RetainedEarningsMember2021-01-012021-12-310001680247us-gaap:CommonStockMember2021-12-310001680247us-gaap:AdditionalPaidInCapitalMember2021-12-310001680247us-gaap:RetainedEarningsMember2021-12-310001680247us-gaap:AdditionalPaidInCapitalMember2022-01-012022-12-310001680247us-gaap:CommonStockMember2022-01-012022-12-310001680247us-gaap:RetainedEarningsMember2022-01-012022-12-310001680247us-gaap:CommonStockMember2022-12-310001680247us-gaap:AdditionalPaidInCapitalMember2022-12-310001680247us-gaap:RetainedEarningsMember2022-12-310001680247pump:SilvertipCompletionServicesOperatingLLCMember2022-11-012022-11-010001680247pump:PioneerandPioneerPumpingServicesMember2018-12-312018-12-31pump:hydraulic_horse_powerpump:coiled_tubing_unit0001680247pump:PioneerandPioneerPumpingServicesMember2018-12-31pump:fleet0001680247pump:ARPressurePumpingServicesMember2022-02-280001680247pump:ARPressurePumpingServicesMember2022-03-310001680247pump:AssetAcquisitionMemberpump:PioneerandPioneerPumpingServicesMember2022-10-31pump:agreementpump:segment00016802472023-01-012022-12-310001680247srt:MinimumMemberus-gaap:BuildingAndBuildingImprovementsMember2022-01-012022-12-310001680247srt:MaximumMemberus-gaap:BuildingAndBuildingImprovementsMember2022-01-012022-12-310001680247us-gaap:VehiclesMembersrt:MinimumMember2022-01-012022-12-310001680247us-gaap:VehiclesMembersrt:MaximumMember2022-01-012022-12-310001680247srt:MinimumMemberus-gaap:EquipmentMember2022-01-012022-12-310001680247us-gaap:EquipmentMembersrt:MaximumMember2022-01-012022-12-310001680247srt:MinimumMemberus-gaap:LeaseholdImprovementsMember2022-01-012022-12-310001680247us-gaap:LeaseholdImprovementsMembersrt:MaximumMember2022-01-012022-12-310001680247pump:PressurePumpingSegmentMember2020-01-012020-12-310001680247pump:DrillingMember2020-01-012020-12-310001680247pump:StimulationServicesLLCMember2011-01-012011-12-310001680247pump:StimulationServicesLLCMember2011-12-310001680247pump:StimulationServicesLLCMember2020-01-012020-12-310001680247pump:SilvertipCompletionServicesOperatingLLCMember2022-11-010001680247us-gaap:CustomerRelationshipsMemberpump:SilvertipCompletionServicesOperatingLLCMember2022-11-010001680247us-gaap:TrademarksAndTradeNamesMemberpump:SilvertipCompletionServicesOperatingLLCMember2022-11-0100016802472022-11-012022-11-01xbrli:pure0001680247srt:MinimumMemberpump:SilvertipCompletionServicesOperatingLLCMember2022-01-012022-12-310001680247srt:MaximumMemberpump:SilvertipCompletionServicesOperatingLLCMember2022-01-012022-12-310001680247pump:SilvertipCompletionServicesOperatingLLCMember2022-01-012022-12-310001680247pump:SilvertipCompletionServicesOperatingLLCMember2021-01-012021-12-310001680247us-gaap:FairValueMeasurementsRecurringMember2022-12-310001680247us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel1Member2022-12-310001680247us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel2Member2022-12-310001680247us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsRecurringMember2022-12-310001680247us-gaap:FairValueMeasurementsRecurringMember2022-01-012022-12-310001680247us-gaap:FairValueMeasurementsRecurringMember2021-12-310001680247us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel1Member2021-12-310001680247us-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueInputsLevel2Member2021-12-310001680247us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsRecurringMember2021-12-310001680247us-gaap:FairValueMeasurementsRecurringMember2021-01-012021-12-310001680247pump:StepEnergyServicesMember2022-09-0100016802472022-10-012022-12-310001680247us-gaap:FairValueInputsLevel3Memberus-gaap:FairValueMeasurementsNonrecurringMember2022-09-2100016802472022-09-212022-09-210001680247pump:PumpingReportableSegmentMember2020-01-012020-03-310001680247pump:PumpingReportableSegmentMember2020-03-012020-03-310001680247pump:WirelineOperatingSegmentMember2020-12-310001680247pump:WirelineOperatingSegmentMember2021-01-012021-12-310001680247pump:WirelineOperatingSegmentMember2021-12-310001680247pump:WirelineOperatingSegmentMember2022-01-012022-12-310001680247pump:WirelineOperatingSegmentMember2022-12-310001680247us-gaap:LandMember2022-12-310001680247us-gaap:LandMember2021-12-310001680247us-gaap:BuildingMember2022-12-310001680247us-gaap:BuildingMember2021-12-310001680247pump:EquipmentandVehiclesMember2022-12-310001680247pump:EquipmentandVehiclesMember2021-12-310001680247us-gaap:LeaseholdImprovementsMember2022-12-310001680247us-gaap:LeaseholdImprovementsMember2021-12-310001680247us-gaap:DiscontinuedOperationsDisposedOfBySaleMemberpump:PressurePumpingSegmentMember2021-12-31pump:turbine0001680247us-gaap:DiscontinuedOperationsDisposedOfBySaleMemberpump:PressurePumpingSegmentMember2021-12-012021-12-310001680247us-gaap:TrademarksAndTradeNamesMember2022-12-310001680247us-gaap:TrademarksAndTradeNamesMember2021-12-310001680247us-gaap:CustomerRelationshipsMember2022-12-310001680247us-gaap:CustomerRelationshipsMember2021-12-310001680247us-gaap:RevolvingCreditFacilityMemberpump:ABLFacilityMemberus-gaap:LineOfCreditMember2022-01-012022-12-310001680247srt:MinimumMemberus-gaap:LondonInterbankOfferedRateLIBORMemberpump:ABLFacilityMember2022-01-012022-12-310001680247us-gaap:LondonInterbankOfferedRateLIBORMembersrt:MaximumMemberpump:ABLFacilityMember2022-01-012022-12-310001680247srt:MinimumMemberus-gaap:BaseRateMemberpump:ABLFacilityMember2022-01-012022-12-310001680247srt:MaximumMemberus-gaap:BaseRateMemberpump:ABLFacilityMember2022-01-012022-12-310001680247srt:MinimumMemberus-gaap:LondonInterbankOfferedRateLIBORMemberpump:ABLFacilityMember2022-12-310001680247us-gaap:RevolvingCreditFacilityMemberpump:ABLFacilityMemberus-gaap:LineOfCreditMember2022-04-130001680247us-gaap:RevolvingCreditFacilityMembersrt:MinimumMemberpump:ABLFacilityMemberus-gaap:LineOfCreditMember2022-04-132022-04-130001680247us-gaap:RevolvingCreditFacilityMembersrt:MaximumMemberpump:ABLFacilityMemberus-gaap:LineOfCreditMember2022-04-132022-04-130001680247us-gaap:RevolvingCreditFacilityMemberpump:ABLFacilityMemberus-gaap:LineOfCreditMember2022-12-310001680247us-gaap:RevolvingCreditFacilityMemberpump:ABLFacilityMemberus-gaap:LineOfCreditMember2022-04-132022-04-130001680247us-gaap:RevolvingCreditFacilityMembersrt:MinimumMemberpump:SOFRLoansMemberpump:ABLFacilityMemberus-gaap:LineOfCreditMember2022-04-132022-04-130001680247us-gaap:RevolvingCreditFacilityMembersrt:MaximumMemberpump:SOFRLoansMemberpump:ABLFacilityMemberus-gaap:LineOfCreditMember2022-04-132022-04-130001680247us-gaap:RevolvingCreditFacilityMembersrt:MinimumMemberpump:BaseRateLoansMemberpump:ABLFacilityMemberus-gaap:LineOfCreditMember2022-04-132022-04-130001680247us-gaap:RevolvingCreditFacilityMemberpump:BaseRateLoansMembersrt:MaximumMemberpump:ABLFacilityMemberus-gaap:LineOfCreditMember2022-04-132022-04-130001680247pump:ABLFacilityMemberus-gaap:LineOfCreditMember2022-12-310001680247pump:ABLFacilityMemberus-gaap:LineOfCreditMember2021-12-3100016802472019-01-012019-01-010001680247pump:FlowbackOperatingSegmentDispoalGroupMemberus-gaap:DisposalGroupDisposedOfBySaleNotDiscontinuedOperationsMember2020-03-310001680247us-gaap:DisposalGroupDisposedOfBySaleNotDiscontinuedOperationsMemberpump:DrillingRigsAndAncillaryAssetsMember2020-09-300001680247us-gaap:DisposalGroupDisposedOfBySaleNotDiscontinuedOperationsMemberpump:CoiledTubingAssetsDivestitureMember2022-09-012022-09-010001680247pump:OperatingSegmentConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerSegmentBenchmarkMemberpump:HydraulicFracturingSegmentMember2022-01-012022-12-310001680247pump:OperatingSegmentConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerSegmentBenchmarkMemberpump:HydraulicFracturingSegmentMember2021-01-012021-12-310001680247pump:OperatingSegmentConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerSegmentBenchmarkMemberpump:HydraulicFracturingSegmentMember2020-01-012020-12-310001680247pump:OperatingSegmentConcentrationRiskMemberpump:CementingSegmentMemberus-gaap:RevenueFromContractWithCustomerSegmentBenchmarkMember2022-01-012022-12-310001680247pump:OperatingSegmentConcentrationRiskMemberpump:CementingSegmentMemberus-gaap:RevenueFromContractWithCustomerSegmentBenchmarkMember2021-01-012021-12-310001680247pump:OperatingSegmentConcentrationRiskMemberpump:CementingSegmentMemberus-gaap:RevenueFromContractWithCustomerSegmentBenchmarkMember2020-01-012020-12-310001680247pump:OperatingSegmentConcentrationRiskMemberpump:WirelineOperatingSegmentMemberus-gaap:RevenueFromContractWithCustomerSegmentBenchmarkMember2022-01-012022-12-310001680247pump:PressurePumpingSegmentMember2022-01-012022-12-310001680247us-gaap:CorporateAndOtherMember2022-01-012022-12-310001680247pump:PressurePumpingSegmentMember2022-12-310001680247us-gaap:CorporateAndOtherMember2022-12-310001680247pump:PressurePumpingSegmentMember2021-01-012021-12-310001680247us-gaap:CorporateAndOtherMember2021-01-012021-12-310001680247pump:PressurePumpingSegmentMember2021-12-310001680247us-gaap:CorporateAndOtherMember2021-12-310001680247us-gaap:CorporateAndOtherMember2020-01-012020-12-310001680247pump:PressurePumpingSegmentMember2020-12-310001680247us-gaap:CorporateAndOtherMember2020-12-310001680247pump:ReimbursementAfterSECInvestigationAndShareholderLitigationMember2022-01-012022-12-310001680247pump:ReimbursementAfterSECInvestigationAndShareholderLitigationMember2021-01-012021-12-310001680247pump:ReimbursementAfterSECInvestigationAndShareholderLitigationMember2020-01-012020-12-310001680247pump:CustomerAMemberus-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMember2022-01-012022-12-310001680247pump:CustomerAMemberus-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMember2021-01-012021-12-310001680247pump:CustomerAMemberus-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMember2020-01-012020-12-310001680247pump:CustomerBMemberus-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMember2022-01-012022-12-310001680247pump:CustomerBMemberus-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMember2021-01-012021-12-310001680247pump:CustomerBMemberus-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMember2020-01-012020-12-310001680247us-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMemberpump:CustomerCMember2022-01-012022-12-310001680247us-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMemberpump:CustomerCMember2021-01-012021-12-310001680247us-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMemberpump:CustomerCMember2020-01-012020-12-310001680247us-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMemberpump:CustomerDMember2022-01-012022-12-310001680247us-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMemberpump:CustomerDMember2021-01-012021-12-310001680247us-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMemberpump:CustomerDMember2020-01-012020-12-310001680247pump:CustomerEMemberus-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMember2022-01-012022-12-310001680247pump:CustomerEMemberus-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMember2021-01-012021-12-310001680247pump:CustomerEMemberus-gaap:RevenueFromContractWithCustomerMemberus-gaap:CustomerConcentrationRiskMember2020-01-012020-12-310001680247pump:PressurePumpingSegmentMemberus-gaap:ProductConcentrationRiskMemberpump:CustomerAMemberus-gaap:RevenueFromContractWithCustomerMember2022-01-012022-12-310001680247pump:PressurePumpingSegmentMemberus-gaap:ProductConcentrationRiskMemberpump:CustomerAMemberus-gaap:RevenueFromContractWithCustomerMember2021-01-012021-12-310001680247pump:PressurePumpingSegmentMemberus-gaap:ProductConcentrationRiskMemberpump:CustomerAMemberus-gaap:RevenueFromContractWithCustomerMember2020-01-012020-12-310001680247pump:CustomerBMemberpump:PressurePumpingSegmentMemberus-gaap:ProductConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerMember2022-01-012022-12-310001680247pump:CustomerBMemberpump:PressurePumpingSegmentMemberus-gaap:ProductConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerMember2021-01-012021-12-310001680247pump:CustomerBMemberpump:PressurePumpingSegmentMemberus-gaap:ProductConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerMember2020-01-012020-12-310001680247pump:PressurePumpingSegmentMemberus-gaap:ProductConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerMemberpump:CustomerCMember2022-01-012022-12-310001680247pump:PressurePumpingSegmentMemberus-gaap:ProductConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerMemberpump:CustomerCMember2021-01-012021-12-310001680247pump:PressurePumpingSegmentMemberus-gaap:ProductConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerMemberpump:CustomerCMember2020-01-012020-12-310001680247pump:PressurePumpingSegmentMemberus-gaap:ProductConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerMemberpump:CustomerDMember2022-01-012022-12-310001680247pump:PressurePumpingSegmentMemberus-gaap:ProductConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerMemberpump:CustomerDMember2021-01-012021-12-310001680247pump:PressurePumpingSegmentMemberus-gaap:ProductConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerMemberpump:CustomerDMember2020-01-012020-12-310001680247pump:PressurePumpingSegmentMemberpump:CustomerEMemberus-gaap:ProductConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerMember2022-01-012022-12-310001680247pump:PressurePumpingSegmentMemberpump:CustomerEMemberus-gaap:ProductConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerMember2021-01-012021-12-310001680247pump:PressurePumpingSegmentMemberpump:CustomerEMemberus-gaap:ProductConcentrationRiskMemberus-gaap:RevenueFromContractWithCustomerMember2020-01-012020-12-310001680247us-gaap:EmployeeStockOptionMember2022-01-012022-12-310001680247us-gaap:EmployeeStockOptionMember2021-01-012021-12-310001680247us-gaap:EmployeeStockOptionMember2020-01-012020-12-310001680247us-gaap:PerformanceSharesMember2022-01-012022-12-310001680247us-gaap:PerformanceSharesMember2021-01-012021-12-310001680247us-gaap:PerformanceSharesMember2020-01-012020-12-310001680247us-gaap:RestrictedStockUnitsRSUMember2022-01-012022-12-310001680247us-gaap:RestrictedStockUnitsRSUMember2021-01-012021-12-310001680247us-gaap:RestrictedStockUnitsRSUMember2020-01-012020-12-310001680247us-gaap:EmployeeStockOptionMember2022-01-012022-12-310001680247us-gaap:EmployeeStockOptionMember2021-01-012021-12-310001680247us-gaap:EmployeeStockOptionMember2020-01-012020-12-310001680247us-gaap:RestrictedStockUnitsRSUMember2022-01-012022-12-310001680247us-gaap:RestrictedStockUnitsRSUMember2021-01-012021-12-310001680247us-gaap:RestrictedStockUnitsRSUMember2020-01-012020-12-310001680247us-gaap:PerformanceSharesMember2022-01-012022-12-310001680247us-gaap:PerformanceSharesMember2021-01-012021-12-310001680247us-gaap:PerformanceSharesMember2020-01-012020-12-310001680247pump:A2017IncentiveAwardPlanMember2017-03-310001680247pump:A2017IncentiveAwardPlanMember2022-01-012022-12-310001680247pump:A2020LongTermIncentivePlanMember2020-10-220001680247us-gaap:EmployeeStockOptionMember2017-03-162017-03-160001680247us-gaap:EmployeeStockOptionMember2017-03-16pump:installment0001680247us-gaap:RestrictedStockUnitsRSUMembersrt:DirectorMemberpump:IncentiveAwardPlanMember2022-01-012022-12-310001680247us-gaap:RestrictedStockUnitsRSUMemberpump:IncentiveAwardPlanMember2022-12-310001680247us-gaap:RestrictedStockUnitsRSUMember2022-12-310001680247us-gaap:RestrictedStockUnitsRSUMember2021-12-310001680247us-gaap:PerformanceSharesMemberpump:A2019Member2021-12-310001680247us-gaap:PerformanceSharesMemberpump:A2019Member2022-01-012022-12-310001680247us-gaap:PerformanceSharesMemberpump:A2019Member2022-12-310001680247us-gaap:PerformanceSharesMemberpump:A2020Member2021-12-310001680247us-gaap:PerformanceSharesMemberpump:A2020Member2022-01-012022-12-310001680247us-gaap:PerformanceSharesMemberpump:A2020Member2022-12-310001680247us-gaap:PerformanceSharesMemberpump:A2021Member2021-12-310001680247us-gaap:PerformanceSharesMemberpump:A2021Member2022-01-012022-12-310001680247us-gaap:PerformanceSharesMemberpump:A2021Member2022-12-310001680247pump:A2022Memberus-gaap:PerformanceSharesMember2021-12-310001680247pump:A2022Memberus-gaap:PerformanceSharesMember2022-01-012022-12-310001680247pump:A2022Memberus-gaap:PerformanceSharesMember2022-12-310001680247us-gaap:PerformanceSharesMember2021-12-310001680247us-gaap:PerformanceSharesMember2022-12-310001680247us-gaap:DomesticCountryMember2022-12-310001680247us-gaap:DomesticCountryMemberpump:Pre2018TaxPeriodsMember2022-12-310001680247us-gaap:StateAndLocalJurisdictionMember2022-12-310001680247pump:FormerExecutiveOfficerAndDirectorMemberpump:RelatedPartyLeasingArrangementsMember2022-12-31pump:property0001680247pump:FormerExecutiveOfficerAndDirectorMemberpump:PropertyOneMemberpump:RelatedPartyLeasingArrangementsMember2022-01-012022-12-310001680247pump:FormerExecutiveOfficerAndDirectorMemberpump:PropertyTwoMemberpump:RelatedPartyLeasingArrangementsMember2022-01-012022-12-310001680247pump:FormerExecutiveOfficerAndDirectorMemberpump:PropertyThreeMemberpump:RelatedPartyLeasingArrangementsMember2022-01-012022-12-310001680247pump:FormerExecutiveOfficerAndDirectorMemberpump:PropertyFourMemberpump:RelatedPartyLeasingArrangementsMember2022-01-012022-12-310001680247pump:FormerExecutiveOfficerAndDirectorMemberpump:PropertyFiveMemberpump:RelatedPartyLeasingArrangementsMember2022-01-012022-12-310001680247pump:AssetAcquisitionMemberpump:PioneerandPioneerPumpingServicesMember2018-12-312018-12-310001680247pump:ARPressurePumpingServicesAgreementMemberpump:AssetAcquisitionMember2022-03-300001680247pump:ARPressurePumpingServicesAgreementMemberpump:AssetAcquisitionMember2022-12-310001680247pump:PioneerandPioneerPumpingServicesMember2022-01-012022-12-310001680247pump:PioneerandPioneerPumpingServicesMember2021-01-012021-12-310001680247pump:PioneerandPioneerPumpingServicesMember2020-01-012020-12-310001680247pump:PioneerandPioneerPumpingServicesMember2022-12-310001680247pump:PioneerandPioneerPumpingServicesMember2021-12-310001680247pump:RealEstateLeaseMember2013-03-310001680247pump:RealEstateLeaseMember2022-12-310001680247pump:MaintenanceFacilityLeaseMember2022-12-310001680247pump:MaintenanceFacilityLeaseMember2022-01-012022-12-31pump:period0001680247pump:ElectricFleetLeaseMember2022-08-3100016802472022-08-30utr:hp0001680247pump:RealEstateTwoLeaseMember2022-10-31pump:leaseRenewalOptions0001680247pump:SilvertipLeaseOneMember2022-11-010001680247pump:SilvertipLeaseTwoMember2022-11-010001680247pump:SilvertipLeaseOneMember2022-11-012022-12-310001680247pump:SilvertipLeaseTwoMember2022-11-012022-12-310001680247pump:SilvertipLeaseTwoMember2022-12-310001680247pump:GroundLeaseMember2018-12-310001680247pump:GroundLeaseMemberus-gaap:LandMember2020-03-012020-03-310001680247pump:ElectricFleetLeaseMember2022-12-310001680247pump:PowerEquipmentLeaseMember2022-12-310001680247pump:InReProPetroHoldingCorpDerivativeLitigationMember2020-05-012020-05-31pump:lawsuit0001680247pump:LoganLawsuitMember2022-10-310001680247pump:TexasComptrollerOfPublicAccountsMember2022-01-310001680247pump:TexasComptrollerOfPublicAccountsMember2021-12-31


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________________
FORM 10-K
______________________________
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2022
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number: 001-38035
______________________________
ProPetro Holding Corp.
(Exact name of registrant as specified in its charter)
______________________________
Delaware 26-3685382
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
1706 South Midkiff,
Midland, Texas 79701
(Address of principal executive offices)
Registrant’s telephone number, including area code: (432) 688-0012
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol(s) Name of each exchange on which registered
Common Stock ($0.001 par value) PUMP New York Stock Exchange
Preferred Stock Purchase Rights N/A New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: 
None
______________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes ý  No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes  ý  No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).     Yes  ý  No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
ý 
Accelerated filer
Non-accelerated filer  
(Do not check if a smaller reporting company)
Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes      No  ý



The aggregate market value of the Company’s Common Stock held by nonaffiliates on June 30, 2022, determined using the per share closing price on the New York Stock Exchange Composite tape of $10.00 on that date, was approximately $726.8 million.
The number of the registrant’s common shares, par value $0.001 per share, outstanding at February 20, 2023, was 115,055,432.




TABLE OF CONTENTS
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

i



FORWARD‑LOOKING STATEMENTS
This Annual Report on Form 10-K (the "Annual Report") contains forward‑looking statements. Statements that are predictive in nature, that depend upon or refer to future events or conditions or that include the words "may," "could," "plan," "project," "budget," "predict," "pursue," "target," "seek," "objective," "believe," "expect," "anticipate," "intend," "estimate," and other expressions that are predictions of, or indicate, future events and trends and that do not relate to historical matters identify forward‑looking statements. Our forward‑looking statements include, among other matters, statements about our business strategy, industry, future profitability, including statements about our expected growth from the Silvertip Acquisition, expected capital expenditures and the impact of such expenditures on our performance and capital programs.
A forward‑looking statement may include a statement of the assumptions or bases underlying the forward‑looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. You are cautioned not to place undue reliance on any forward‑looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward‑looking statements include:
operational challenges from the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;
the severity and duration of any world events and armed conflict, like the Russian-Ukraine war and associated repercussions to supply and demand for oil and gas and the economy generally;
the actions taken by the members of the Organization of the Petroleum Exporting Countries ("OPEC") and Russia (together with OPEC and other allied producing countries, "OPEC+") with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;
actions taken by the Biden Administration, such as executive orders or new regulations, that may negatively impact the future production of oil and natural gas in the United States and may adversely affect our future operations;
the level of production and resulting market prices for crude oil, natural gas and other hydrocarbons;
changes in general economic and geopolitical conditions, including increasing interest rates, the rate of inflation and potential economic recession;
the effects of existing and future laws and governmental regulations (or the interpretation thereof) on us, our suppliers and our customers;
cost increases and supply chain constraints related to our services;
competitive conditions in our industry;
our ability to attract and retain employees;
changes in the long-term supply of, and demand for, oil and natural gas;
actions taken by our customers, suppliers, competitors and third-party operators and the possible loss of customers or work to our competitors;
technological changes, including lower emissions oilfield services equipment and similar advancements;
changes in the availability and cost of capital;
our ability to successfully implement our business plan, including integrating the recently acquired wireline business from the Silvertip Acquisition and execution of other potential mergers and acquisitions;
large or multiple customer defaults, including defaults resulting from actual or potential insolvencies;
the effects of consolidation on our customers or competitors;
the price and availability of debt and equity financing (including increasing interest rates) for the Company and our customers;
our ability to complete growth projects on time and on budget;
i



increases in tax rates or types of taxes enacted that specifically impact E&P operations resulting in changes in the amount of taxes owed by us;
regulatory and related policy actions intended by federal, state and/or local governments to reduce fossil fuel use and associated carbon emissions, or to drive the substitution of renewable forms of energy for oil and gas, may over time reduce demand for oil and gas and therefore the demand for our services;
new or expanded regulations that materially limit our customers’ access to federal and state lands for oil and gas development, thereby reducing demand for our services in the affected areas;
growing demand for electric vehicles that result in reduced demand for gasoline and therefore the demand for our services;
our ability to successfully implement technological developments and enhancements, including our new Tier IV DGB and electric hydraulic fracturing equipment, and other lower-emissions equipment we may acquire or that may be sought by our customers;
operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control, which risks may be self-insured, or may not be fully covered under our insurance programs;
exposure to cyber-security events which could cause operational disruptions or reputational harm;
acts of terrorism, war or political or civil unrest in the United States or elsewhere; and
the effects of current and future litigation.
You should not place undue reliance on our forward‑looking statements. Although forward‑looking statements reflect our good faith beliefs at the time they are made, forward‑looking statements involve known and unknown risks, uncertainties and other factors, including the factors described under "Item 1A. Risk Factors" of this Annual Report, which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward‑looking statements. We undertake no obligation to publicly update or revise any forward‑looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.
Unless the context indicates otherwise, all references to "ProPetro Holding Corp.," "the Company," "we," "our" or "us" or like terms refer to ProPetro Holding Corp. and its consolidated subsidiaries, ProPetro Services, Inc. and Silvertip Completion Services Operating, LLC.

ii



SUMMARY RISK FACTORS
Our business is subject to varying degrees of risk and uncertainty. Investors should consider the risks and uncertainties summarized below, as well as the risks and uncertainties discussed in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. Additional risks not presently known to us or that we currently deem immaterial may also affect us. If any of these risks occur, our business, financial condition or results of operations could be materially and adversely affected.
Our business is subject to the following principal risks and uncertainties:
Risks Inherent in Our Business and Industry
Our business and financial performance depends on the historically cyclical oil and natural gas industry and particularly on the level of capital spending and exploration and production activity within the United States and in the Permian Basin, and a decline in prices for oil and natural gas may cause fluctuation in operating results or otherwise have an adverse effect on our revenue, cash flows, profitability and growth.
The cyclical nature of the oil and natural gas industry may cause our operating results to fluctuate.
The majority of our operations are located in the Permian Basin, making us vulnerable to risks associated with operating in one major geographic area.
The Inflation Reduction Act of 2022 ("IRA 2022") could accelerate the transition to a low carbon economy and could impose new costs on our customers’ operations.
The COVID-19 outbreak has negatively impacted, and may continue to negatively impact crude oil prices and demand for our products and services.
Our business may be adversely affected by a deterioration in general economic conditions or a weakening of the broader energy industry.
Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms, or at all, which could limit our ability to grow.
Our indebtedness and liquidity needs could restrict our operations and make us more vulnerable to adverse economic conditions.
Restrictions in our Asset Backed Loan (ABL) Credit Facility (as defined herein) and any future financing agreements may limit our ability to finance future operations or capital needs or capitalize on potential acquisitions and other business opportunities.
Our operations are subject to unforeseen interruptions and hazards inherent in the oil and natural gas industry, for which we may not be adequately insured and which could cause us to lose customers and substantial revenue.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
We may grow through acquisitions and our failure to properly plan and manage those acquisitions may adversely affect our performance.
Risks Related to Customers, Suppliers and Competition
Reliance upon a few large customers may adversely affect our revenue and operating results.
We face significant competition that may cause us to lose market share, and competition in our industry has intensified during the recent industry downturn.
We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our business, results of operations and financial conditions.
Our business depends upon the ability to obtain specialized equipment, parts and key raw materials, including sand and chemicals, from third‑party suppliers, and we may be vulnerable to delayed deliveries and future price increases.
iii



We may be required to pay fees to certain of our sand suppliers based on minimum volumes under long-term contracts regardless of actual volumes received.
Risks Related to Employees
We rely on a few key employees whose absence or loss could adversely affect our business.
If we are unable to employ a sufficient number of skilled and qualified workers, our capacity and profitability could be diminished and our growth potential could be impaired.
Risks Related to Regulatory Matters
We are subject to environmental laws and regulations, and future compliance, claims, and liabilities relating to such matters may have a material adverse effect on our results of operations, financial position or cash flows.
Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Increased attention to environmental, social and governance matters, conservation measures, commercial development and technological advances could reduce demand for oil and natural gas and our services.
Certain of our completion services, particularly our hydraulic fracturing services, are substantially dependent on the availability of water. Restrictions on our or our customers’ ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Risks Related to our Tax Matters
Our ability to use our net operating loss carryforwards may be limited.
Risks Inherent to an Investment in our Common Stock
We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act ("Section 404"). If we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.
Certain provisions of our certificate of incorporation, and bylaws, as well as Delaware law, may discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our business could be negatively affected as a result of the actions of activist shareholders.
Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to pursue actions in another judicial forum for disputes with us or our directors, officers, employees or agents.
There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.
iv



PART I
Item 1.     Business.
Our Company
We are a leading integrated oilfield services company, located in Midland, Texas, focused on providing innovative hydraulic fracturing, wireline, and other complementary oilfield completion services to leading upstream oil and gas companies engaged in the exploration and production ("E&P") of North American oil and natural gas resources. Our operations are primarily focused in the Permian Basin, where we have cultivated longstanding customer relationships with some of the region’s most active and well‑capitalized E&P companies. The Permian Basin is widely regarded as one of the most prolific oil‑producing areas in the United States, and we believe we are one of the leading providers of completion services in the region.
On November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip Completion Services Operating, LLC (the "Silvertip Acquisition"), which provides wireline perforation and ancillary services solely in the Permian Basin in exchange for 10.1 million shares of our common stock valued at $106.7 million, $30.0 million of cash, the payoff of $7.2 million of assumed debt, and the payment of certain other closing and transaction costs. The Silvertip Acquisition positions the Company as a leading completions-focused oilfield services provider headquartered in the Permian Basin.
Our competitors include many large and small oilfield services companies, including Halliburton Company, Liberty Energy Inc., ProFrac Holding Corp., Nextier Oilfield Solutions Inc., Patterson-UTI Energy Inc., RPC, Inc., and a number of private and locally-oriented businesses. The markets in which we operate are highly competitive. To be successful, an oilfield services company must provide services that meet the specific needs of oil and natural gas E&P companies at competitive prices. Competitive factors impacting sales of our services are price, reputation, technical expertise, emissions profile, service and equipment design and quality, and health and safety standards. Although we believe our customers consider all of these factors, we believe price is a key factor in E&P companies' criteria in choosing a service provider. However, we have recently observed the energy industry and our customers shift to lower emissions equipment, which we believe will be an increasingly important factor in an E&P company's selection of a service provider. The transition to lower emissions equipment has been challenging for companies in the service industry because of the capital requirements, lack of large scale deployment of certain new technology such as electric powered equipment, and the pricing for our services and expected return on invested capital. While we seek to price our services competitively, we believe many of our customers elect to work with us based on our operational efficiencies, productivity, equipment quality, reliability, ability to manage multifaceted logistics challenges, commitment to safety and the ability of our people to handle the most complex Permian Basin well completions.
Our substantial market presence in the Permian Basin positions us well to capitalize on drilling and completion activity in the region. Our operational focus has primarily been in the Permian Basin's Midland sub-basin, where our customers have operated. However, we have increased our operations in the Delaware sub-basin and are well-positioned to support further increases to our activity in this area in response to demand from our customers. Over time, we expect the Permian Basin's Midland and Delaware sub-basins to continue to command a disproportionate share of future North American E&P spending.
We primarily provide hydraulic fracturing, wireline, and cementing completion services to E&P companies in the Permian Basin. Our equipment has been designed to handle the operating conditions commonly encountered in the Permian Basin and the region's increasingly high-intensity well completions (including Simul-Frac, which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well.
Effective September 1, 2022, we disposed of our coiled tubing assets to STEP Energy Services (USA) Ltd. ("STEP") and shut down our coiled tubing operations. We received approximately $2.8 million in cash and 2.6 million common shares of STEP, which have an estimated fair value of $11.8 million, as consideration. Upon the sale of our coiled tubing assets, we recorded a loss on sale of $13.8 million.
Commodity Price and Other Economic Conditions
The oil and gas industry has traditionally been volatile and is characterized by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves. The oil and gas industry is also impacted by general domestic and international economic conditions such as supply chain disruptions and inflation, war and political instability in oil producing
1



countries, government regulations (both in the United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control.
The global public health crisis associated with the COVID-19 pandemic has had an adverse effect on global economic activity and the oil and gas industry in 2020 and 2021. Some of the challenges resulting from the COVID-19 pandemic that have impacted our business include restrictions on movement of personnel and associated gatherings, shortage of skilled labor, cost inflation and supply chain disruptions. In light of the COVID-19 pandemic, most companies, including our customers in the Permian Basin, reacted by closely managing their operating budget and exercising capital discipline in 2020 and 2021.
In February 2022, Russia launched a large-scale invasion of Ukraine that has led to significant armed hostilities. As a result, the United States, the United Kingdom, the member states of the European Union and other public and private sectors have levied severe sanctions on Russian financial institutions, businesses and individuals. This conflict, and the resulting sanctions, have contributed to significant increases and volatility in the prices for oil and natural gas. The geopolitical and macroeconomic consequences of this invasion and associated sanctions remain uncertain, and such events, or any further hostilities in Ukraine or elsewhere, could severely impact the world economy and the oil and gas industry and may adversely affect our financial condition.
The Russia-Ukraine war, and the adverse impacts of the COVID-19 pandemic in recent years, including inflation, have resulted in volatility in supply and demand dynamics for crude oil and associated volatility in crude oil pricing. In 2022, West Texas Intermediate ("WTI") average crude oil price was approximately $94 per barrel, which is the highest average price in the last nine years. We believe that the recent surge in global crude oil prices is partly due to the lack of reinvestment in the oil and gas industry in the last two years, and increased demand for oil and gas products, coupled with the adverse impact of the Russia-Ukraine war, which has led to various sanctions on Russian crude oil supply and businesses. With the significant increase in global crude oil prices, including WTI crude oil prices, there has been an increase in the Permian Basin rig count from approximately 179 at the beginning of 2021 to approximately 353 at the end of December 2022, according to Baker Hughes. Following the increase in rig count and WTI crude oil price, the oilfield service industry has experienced increased demand for its oil well completion services, and improved pricing. As a result of the growing demand for oil well completion services and significant cost inflation across the industry, we negotiated pricing increases with certain of our customers for our oil well completion services, depending on job design. Although we are currently operating in an improved pricing environment compared to 2020 and 2021, the rapid increase in cost inflation and supply chain tightness could adversely impact our future profitability. The U.S. inflation rate has been steadily increasing since 2021. These inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including labor costs and equipment. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to timely pass-through the cost increases to our customers, would negatively impact our business, financial condition and results of operations. See Part II, Item 1A. "Risk Factors—Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise."
Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including the upstream and oilfield services companies. As a result, we are working with our customers and equipment manufacturers to transition our equipment to a lower emissions profile. Currently, a number of lower emission solutions for pumping equipment, including Tier IV Dynamic Gas Blending ("DGB"), electric, direct drive gas turbine and other technologies have been developed, and we expect additional lower emission solutions will be developed in the future. We are continually evaluating these technologies and other investment and acquisition opportunities that would support our existing and new customer relationships. The transition to lower emissions equipment is quickly evolving and will be capital intensive. Over time, we may be required to convert substantially all of our conventional Tier II equipment to lower emissions equipment. We have transitioned our active hydraulic fracturing equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022, and expect to increase to approximately 65% in 2023.
The Permian Basin rig count increase, demand for oil and gas products, WTI crude oil price increase and costs inflation could be indicative of an energy market recovery. If the rig count and market conditions continue to improve, including improved customers' pricing and labor availability, and we are able to continue to meet our customers' lower emissions equipment demands, we believe our operational and financial results will also continue to improve. However, if market conditions do not improve or decline in the future, and we are unable to increase our pricing or pass-through future cost increases to our customers, there could be a material adverse impact on our business, results of operations and cash flows.
2



Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to the holiday season, inclement winter weather and exhaustion of our customers' annual budgets. As a result, we typically experience declines in our operating and financial results in November and December, even in a stable commodity price and operations environment.
Our Services
We have historically conducted our business through five operating segments: hydraulic fracturing, cementing, coiled tubing, drilling and flowback. For reporting purposes, the hydraulic fracturing and cementing operating segments were aggregated into one reportable segment—"Pressure Pumping" while coiled tubing, drilling and flowback operating segments, and corporate administrative expenses were aggregated into the "All Other" category. In connection with the Silvertip Acquisition, we now have a wireline operating segment which has been aggregated with Pressure Pumping. Additionally, the divestitures of our coiled tubing operations in September 2022 and our drilling and flowback operations in 2020 resulted in the "All Other" category having no operating segments and therefore in 2022, our corporate administrative expenses were aggregated into "Pressure Pumping", and prior periods have been restated accordingly. During the fourth quarter of 2022, we renamed our "Pressure Pumping" reportable segment to "Completion Services" since the Company is now positioned to provide highly complementary completion services to its customers and has significant cross-selling opportunities across its combined customer base. For additional financial information on our reportable segments presentation, please see reportable segment information in Part II - Item 8, "Financial Statements and Supplementary Data."
Completion Services
Hydraulic Fracturing
We provide hydraulic fracturing services to E&P companies in the Permian Basin. These services are intended to optimize hydrocarbon flow paths during the completion phase of horizontal shale wellbores. We have significant expertise in multi‑stage fracturing of horizontal oil‑producing wells in unconventional geological formations. Our total available hydraulic horsepower ("HHP") at December 31, 2022 was 1,315,000 HHP, which was comprised of 252,500 HHP of our Tier IV DGB equipment and 1,062,500 HHP of conventional Tier II equipment. An individual fleet could range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsite. During the year ended December 31, 2022, we recorded an impairment with respect to our DuraStim® hydraulic fracturing pumps (108,000 HHP) that did not meet the manufacturer’s specifications or our expectations and have remained idled. With the industry transition to lower emissions equipment and simultaneous hydraulic fracturing ("Simul-Frac"), in addition to several other changes to our customers' job designs, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites. In addition, in September 2021, August 2022 and December 2022, we committed to additional conversions of our Tier II equipment to Tier IV DGB, and purchase of new Tier IV DGB equipment. As such, we entered into conversion and purchase agreements with our equipment manufacturers for a total of 362,500 HHP of Tier IV DGB equipment and as of December 31, 2022, we have received 192,500 HHP of the converted and new Tier IV DGB equipment and expect to receive the remaining 170,000 HHP by the second quarter of 2023. In August 2022 and December 2022, we entered into leases for four electric fleets of 60,000 HHP per fleet. We expect to take delivery of the electric fleets at different times during the second half of 2023. We have entered into a contract with a customer for the use of one of our electric hydraulic fracturing fleets to provide committed services for a period of three years after we take delivery of the fleet.
The hydraulic fracturing process consists of pumping fracturing fluid into a well at sufficient pressure to fracture the formation. Materials known as proppants, which in our business are comprised primarily of sand, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. The fracturing fluid is designed to break, or loosen viscosity, and be forced out of the formation by its pressure, leaving the proppants suspended in the fractures created, thereby increasing the mobility of the hydrocarbons. As a result of the fracturing process, production rates are usually enhanced substantially, thus increasing the rate of return of hydrocarbons for the operator.
We own and operate a fleet of mobile hydraulic fracturing units and other auxiliary equipment to perform fracturing services. We also refer to all of our fracturing units, other equipment and vehicles necessary to perform a fracturing job as a "fleet" and the personnel assigned to each fleet as a "crew." Our hydraulic fracturing units consist primarily of a high pressure hydraulic pumps, diesel or dual gas engines, transmissions and various hoses, valves, tanks and other supporting equipment like blenders, irons, hoses and datavans.
We provide dedicated equipment, personnel and services that are tailored to meet each of our customer’s needs. Each fleet has a designated team of personnel, which allows us to provide responsive and customized services, such as project design, proppant and other consumables procurement, real‑time data provision and post‑completion analysis for each of our jobs. Many of our
3



hydraulic fracturing fleets and associated personnel have worked continuously with the same customer for the past several years promoting deep relationships and a high degree of coordination and visibility into future customer activity levels. Furthermore, in light of our substantial market presence and historically high fleet utilization levels, we have established a variety of trusted relationships with key equipment, sand and other downhole consumable suppliers. We believe these strategic relationships position us to acquire equipment, parts and materials on a timely and economic basis and allow our dedicated procurement and logistics team to support consistently safe and reliable operations.
Cementing
We provide cementing services for completion of new wells and remedial work on existing wells. Cementing services use pressure pumping equipment to deliver a slurry of liquid cement that is pumped down a well between the casing and the borehole. Cementing provides isolation between fluid zones behind the casing to minimize potential damage to hydrocarbon bearing formations or the integrity of freshwater aquifers, and provides structural integrity for the casing by securing it to the earth. Cementing is also done when re-completing wells, where one zone is plugged and another is opened.
We believe that our cementing segment provides an organic growth opportunity for us to expand our service offerings within our existing customer base.
Wireline
We provide wireline and ancillary services such as pumpdown on new oil well completions in the Permian Basin. Wireline utilizes equipment with a drum of wireline to deploy perforating guns in the well to perforate the casing, cement, and formation. Once the well is perforated, it is ready to be fractured. Pumpdown utilizes pressure pumping equipment to pump water into the well to deploy or push the perforating guns attached to wireline through the lateral section of a well.
We own and operate a fleet of mobile wireline units and other auxiliary equipment to perform well completion services. We also refer to our wireline units, pressure control equipment, other equipment and vehicles necessary to perform a job as a "spread" and the personnel assigned to the spread as a "crew." On average, one wireline spread consists of a wireline tractor truck with a large cab functioning as mobile office where the engineer controls the wireline spooled drum along with associated pressure control iron and equipment, trailers and vehicles. We currently have 23 wireline units.

Other Services
Coiled Tubing
Coiled tubing services involve injecting coiled tubing into wells to perform various completion well intervention operations. Coiled tubing is a flexible steel pipe with a diameter of typically less than three inches and manufactured in continuous lengths of thousands of feet. It is wound or coiled on a truck‑mounted reel for onshore applications. Due to its small diameter, coiled tubing can be inserted into existing production tubing and used to perform a variety of services (including drillout of plugs) to enhance the flow of oil or natural gas. Effective September 1, 2022, we shut down our coiled tubing operations and disposed of all of the assets.
Our Customers
Our customers consist primarily of oil and natural gas producers in North America. Our top five customers accounted for approximately 84.0%, 85.7% and 86.5% of our revenue, for the years ended December 31, 2022, 2021 and 2020, respectively. For the year ended December 31, 2022, Pioneer Natural Resources USA Inc. ("Pioneer"), Endeavor Energy Resources and XTO Energy accounted for 33.1%, 28.3% and 15.0%, respectively, of total revenue. No other customer accounted for more than 10% of our total revenue for the year ended December 31, 2022.
On March 31, 2022, we entered into an amended and restated pressure pumping services agreement (the "A&R Pressure Pumping Services Agreement") with Pioneer, which was initially entered into in connection with our purchase of certain pressure pumping assets and real property from Pioneer and Pioneer Pumping Services (the "Pioneer Pressure Pumping Acquisition"). The A&R Pressure Pumping Services Agreement, which was effective from January 1, 2022 to December 31, 2022, reduced the number of contracted fleets to six fleets from eight fleets, modified the pressure pumping scope of work and pricing mechanism for contracted fleets, and replaced the idle fees arrangement with equipment reservation fees (the "Reservation fees"). As part of the Reservation fees arrangement, the Company was entitled to receive compensation for all eligible contracted fleets that were made available to Pioneer at the beginning of every quarter in 2022 through the term of the A&R Pressure Pumping Services Agreement. The A&R Pressure Pumping Services Agreement expired at the conclusion of its term and was replaced by the Fleet One Agreement and the Fleet Two Agreement described below.
4



On October 31, 2022, we entered into two pressure pumping services agreements with Pioneer, pursuant to which we will provide hydraulic fracturing services with two committed fleets, subject to certain termination and release rights. The Fleet One Agreement was effective as of January 1, 2023 and will terminate on August 31, 2023. The Fleet Two Agreement was effective as of January 1, 2023 and was originally planned to terminate on the one year anniversary of the date on which the fleet dedicated thereunder converted from a Tier II diesel Simul-Frac fleet to a Tier IV dual fuel zipper fleet, which was expected to occur in May 2023. In February 2023, Pioneer provided the Company notice (i) stating that Pioneer intended to release Fleet Two effective upon the completion of operations on the pad where the performance of Services (as defined in the Fleet Two Agreement) is in progress on May 12, 2023 (the “Release Date”) and (ii) requesting that the Company agree to the termination of the Fleet Two Agreement as of the Release Date. The Company agreed with such request, and, as a result, the Fleet Two Agreement will be terminated as of the Release Date.
Competition
The markets in which we operate are highly competitive. To be successful, an oilfield services company must provide services and equipment that meet the specific needs of oil and natural gas E&P companies at competitive prices. Competitive factors impacting sales of our services are price, reputation, technical expertise, emissions profile, service and equipment design and quality, and health and safety standards. Although we believe our customers consider all of these factors, we believe price is a key factor in E&P companies’ criteria in choosing a service provider. However, we have recently observed the energy industry and our customers shift to lower emissions equipment, which we believe will be an increasingly important factor in an E&P company’s selection of a service provider. The transition to lower emissions equipment has been challenging for companies in the oilfield service industry because of the capital requirements. While we seek to price our services competitively, we believe many of our customers elect to work with us based on our operational efficiencies, productivity, equipment portfolio and quality, reliability, ability to manage multifaceted logistics challenges, commitment to safety and the ability of our people to handle the most complex Permian Basin well completions.
We provide our services primarily in the Permian Basin, and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield services companies, including the largest integrated oilfield services companies. Our major competitors include Halliburton Company, Liberty Energy Inc., ProFrac Holding Corp., Nextier Oilfield Solutions Inc., Patterson‑UTI Energy Inc., RPC, Inc., and a number of private and locally-oriented businesses.
Seasonality
Our results of operations have historically reflected seasonal tendencies, generally in the fourth quarter, relating to the conclusion of our customers’ annual capital expenditure budgets, the holidays and inclement winter weather during which we may experience declines in our operating and financial results.
Operating Risks and Insurance
Our operations are subject to hazards inherent in the oilfield services industry, such as accidents, blowouts, explosions, fires and spills and releases that can cause personal injury or loss of life, damage or destruction of property, equipment, natural resources and the environment and suspension of operations.
In addition, claims for loss of oil and natural gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims.
Our business involves the transportation of heavy equipment and materials, and as a result, we may also experience traffic accidents which may result in spills, property damage and personal injury.
Despite our efforts to maintain safety standards, we have suffered accidents from time to time in the past and anticipate that we could experience accidents in the future. In addition to the property damage, personal injury and other losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees, regulatory agencies and other parties. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.
5



We maintain commercial general liability, workers’ compensation, business automobile, commercial property, umbrella liability, excess liability, and directors and officers insurance policies providing coverages of risks and amounts that we believe to be customary in our industry. Further, we have pollution legal liability coverage for our business entities, which would cover, among other things, third party liability and costs of clean up relating to environmental contamination on our premises while our equipment is in transit and on our customers’ job site. With respect to our operations, coverage would be available under our pollution legal liability policy for any surface or subsurface environmental clean‑up and liability to third parties arising from any surface or subsurface contamination. We also have certain specific coverages for some of our businesses, including our hydraulic fracturing and wireline services.
We maintain directors and officers insurance; however, our insurance coverage is subject to certain exclusions (including, for example, any required SEC disgorgement or penalties) and we are responsible for meeting certain deductibles under the policies. Moreover, we cannot assure you that our insurance coverage will adequately protect us from all future claims.
Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. See "Risk Factors" for a description of certain risks associated with our insurance policies.
Environmental and Occupational Health and Safety Regulations
Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, and occupational health and safety. Numerous federal, state and local governmental agencies issue regulations that often require difficult and costly compliance measures that could carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may, for example, restrict the types, quantities and concentrations of various substances that can be released into the environment, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas and other protected areas, or require action to prevent or remediate pollution from current or former operations. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental, health and safety laws and regulations occur frequently, and any changes that result in more stringent and costly requirements could materially adversely affect our operations and financial position. For example, following the election of President Biden and passage of laws such as the IRA 2022, it is possible that our operations may be subject to greater environmental, health and safety restrictions, particularly with regards to hydraulic fracturing and wireline, permitting and greenhouse gases ("GHG") emissions. We have not experienced any material adverse effect from compliance with current requirements; however, this trend may not continue in the future.
Below is an overview of some of the more significant environmental, health and safety requirements with which we must comply. Our customers’ operations are subject to similar laws and regulations. Any material adverse effect of these laws and regulations on our customers’ operations and financial position may also have an indirect material adverse effect on our operations and financial position.
Waste Handling. We handle, transport, store and dispose of wastes that are subject to the Resource Conservation and Recovery Act ("RCRA") and comparable state laws and regulations, which affect our activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although certain petroleum production wastes are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions.
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Moreover, the U.S. Environmental Protection Agency ("EPA") or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or recategorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to recategorize certain oil and natural gas exploration, development and production wastes as hazardous wastes. Several environmental organizations have also petitioned the EPA to modify existing regulations to recategorize certain oil and natural gas exploration, development and production wastes as hazardous. Any such changes in these laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any
6



legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund") and analogous state laws generally impose liability without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Liability for the costs of removing or remediating previously disposed wastes or contamination, damages to natural resources, the costs of conducting certain health studies, amongst other things, is strict and joint and several. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state laws. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such hazardous substances have been released.
NORM. In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials ("NORM") associated with oil and gas deposits and, accordingly, may result in the generation of wastes and other materials containing NORM. NORM exhibiting levels of radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements.
Water Discharges. The Clean Water Act, Safe Drinking Water Act, Oil Pollution Act and analogous state laws and regulations impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Also, spill prevention, control and countermeasure plan requirements require appropriate containment berms and similar structures to help prevent the contamination of regulated waters.
Air Emissions. The Clean Air Act ("CAA") and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other emissions control requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants from specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. These and other laws and regulations may increase the costs of compliance for some facilities where we operate. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects.
Climate Change. In the United States, no comprehensive climate change legislation has been implemented at the federal level, though recently passed laws such as the IRA 2022 advance numerous climate-related objectives. Additionally, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of certain pollutants from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the Department of Transportation ("DOT"), implementing GHG emissions limits on vehicles manufactured for operation in the United States. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, subsequently, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally, the EPA has proposed more recent rules covering the standards of performance for methane and volatile organic compounds emissions for oil and gas facilities, including leak detection, monitoring and repair, and a "super-emitter" response program to timely mitigate emissions events as detected by governmental agencies or qualified third parties. Certain of these requirements are currently subject to public comment, and the rule is expected to be finalized in 2023; however, it is likely that these requirements will be subject to legal challenge.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas such as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored "Paris Agreement," requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined Contributions ("NDCs") every five years after 2020. Following President Biden’s executive order in January 2021, the United States rejoined the Paris Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below 2005 levels by 2030. Some countries, including the United States, have additionally made commitments to reduce global methane
7



emissions through initiatives such as the Global Methane Pledge, and have been called upon to phase out inefficient fossil fuel subsidies. However, the impacts of these actions are unclear at this time. For more information, see our risk factors titled "Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide" and "The IRA 2022 could accelerate the transition to a low carbon economy and could impose new costs on our customers’ operations."
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate-change-related pledges made by certain candidates for public office. On January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry and an increased emphasis on climate-related risk across government agencies and economic sectors. The executive order also suspends the issuance of new leases for oil and gas development on federal land; for more information, see our regulatory disclosure titled "Regulation of Hydraulic Fracturing and Related Activities." Other actions that the Biden Administration may take include the imposition of more restrictive requirements for the development of pipeline infrastructure or liquefied natural gas export facilities or more restrictive GHG emissions limitations for oil and gas facilities. Litigation risks are also increasing as a number of parties have sought to bring suit against certain oil and natural gas companies operating in the United States in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or that such companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts to their investors or customers.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our services and products.
Moreover, climate change may result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in the meteorological and hydrological patterns, that could adversely impact us, our customers’ and our suppliers’ operations. Such physical risks may result in damage to our customers’ facilities or otherwise adversely impact our operations, such as if facilities are subject to water use curtailments in response to drought, or demand for our customers’ products, such as to the extent warmer winters reduce the demand for energy for heating purposes, which may ultimately reduce demand for the products and services we provide. Such physical risks may also impact our suppliers, which may adversely affect our ability to provide our products and services. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured.
Endangered and Threatened Species. Environmental laws such as the Endangered Species Act ("ESA") and analogous state laws may impact exploration, development and production activities in areas where we operate. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and various state analogs. The U.S. Fish and Wildlife Service ("FWS") may identify previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. For example, the dunes sagebrush lizard, which is found only in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas (including areas where our customers operate), was a candidate species for listing under the ESA by the FWS for many years. As a result of a recent settlement with certain environmental groups, the FWS, in July 2020, acted on a petition to list the dunes sagebrush lizard finding sufficient information to warrant a formal one-year review to consider listing the species. While that deadline has been missed, the listing review is reportedly ongoing and a decision is expected in June 2023; additionally, FWS has also solicited comments on a proposed conservation agreement that would implement certain protective practices for the species and authorize incidental take of the species resulting from certain covered activities, including exploration and development of oil and gas fields. However, to the extent any protections are implemented for this or any other species, it could cause us or our customers to incur additional costs or become subject to operating restrictions or operating bans in the affected areas.
Regulation of Hydraulic Fracturing and Related Activities. Our hydraulic fracturing operations are a significant component of our business. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. Although several of these rulemakings have been rescinded, modified or subjected to legal challenges, new or more
8



stringent regulations may be promulgated by the Biden administration. For example, the Bureau of Land Management (“BLM”) recently proposed a rule that would limit flaring from well sites on federal lands, as well as allow the delay or denial of permits if BLM finds that an operator’s methane waste minimization plan is insufficient. The Biden Administration has also called for revisions and restrictions to the leasing and permitting programs for oil and gas development on federal lands and, for a time, suspended federal oil and gas leasing activities. The Department of the Interior ("DOI") has also issued a report recommending various changes to the federal leasing program, though many such changes would require Congressional action. As a result, we cannot predict the final scope of regulations or restrictions that may apply to oil and gas operations on federal lands. However, any regulations that ban or effectively ban such operations may adversely impact demand for our products and services. Further, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have previously been proposed in Congress. Several states and local jurisdictions in which we or our customers operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.

Federal and state governments have also investigated whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for wastewater disposal wells that impose permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In particular, the Oklahoma Corporation Commission’s well completion seismicity guidelines for operators in the SCOOP and STACK require hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division has previously issued an order limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state. The Texas Railroad Commission ("TRRC") has adopted similar rules including the indefinite suspension of all deep oil and gas produced water injection wells in certain areas covered by the TRRC’s seismic response program.
Increased regulation of hydraulic fracturing and related activities could subject us and our customers to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and record keeping obligations, and plugging and abandonment requirements. New requirements could result in increased operational costs for us and our customers, and reduce the demand for our services. For more information on each of these items, see our risk factor titled "Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays."
OSHA Matters. The Occupational Safety and Health Act ("OSHA") and comparable state statutes regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public.
Human Capital
Our employees are our key asset. Our primary human capital management objectives are to effectively engage, develop, retain and reward our employees. As of December 31, 2022, we employed approximately 2,000 people, none of which are unionized. All of our employees work for or support our Completion Services reportable segment. Our employees are a key component of our ability to attract and retain customers as a result of their operational excellence in the field.
Some examples of significant programs and initiatives that are focused to attract, develop and retain our diverse workforce include:
Diversity and inclusion. We believe that in order to attract and retain talent with the skill sets and expertise required to maximize our operational efficiencies across all levels in the Company, it is in our best interest to attempt to recruit and develop a diverse team and create a culture that is inclusive and provides equal opportunities for hiring and advancement for all employees and prospective employees. Some examples of this effort include;
a commitment to conducting business in a manner that respects all human rights in compliance within the requirements of applicable laws;
9



efforts to promote and encourage respect for human rights and fundamental freedoms for all without distinctions of any kind such as race, color, sex, language, religion, political or other opinions;
working in partnership with personnel, business parties and other parties directly linked to our operations that share our commitment to these same principles;
efforts in our employment practices, including through our code of conduct, our equal employment opportunity employer policy, and our anti-harassment policy; and
to make it possible for grievances regarding health and safety to be addressed early and remediated directly, in confidence and without fear of retaliation; the Company provides an anonymous Ethics and Compliance hotline that is promoted internally and accessible from our intranet and internet.
Training and Safety. We offer in-depth, role-appropriate safety training upon hiring and as part of the continuous development of our employees. The safety of our employees, our customers, and the communities in which we operate is paramount. We track and evaluate safety incidents at wellsites and offices, and if an accident does occur, we take actions to mitigate similar incidents from reoccurring in the future. The Company incentivizes employees to focus on conducting operations in accordance with our strict safety standards and encourages employees to immediately report any breach of safety protocol. Ten percent of our executive officers’ annual target bonuses under the 2022 annual incentive program were based upon the Company’s achievement of certain safety goals, including a target total recordable incident rate of less than 0.65.
Professional Development. In 2022, ProPetro launched a leadership training initiative for all positions that are responsible for supervision and oversight of other employees. This effort includes development of 255 frontline and above leadership positions over a seven month period. In 2021, ProPetro introduced a Tuition Reimbursement Program to encourage employees to pursue professional development interests that will help strengthen skills and competencies required for their current position or future roles in the business.

Health, Wellness and Benefits. Our employee benefit offerings are designed to meet the varied and evolving needs of a diverse workforce across the Company and we believe are consistent with those provided by our peer companies with which we compete for talent. The Company provides employees with the ability to participate in health and welfare plans, including medical, dental, life, accidental death and dismemberment and short-term and long-term disability insurance plans.
We periodically review of our health-related benefits program to ensure that our offerings are market competitive and effectively utilized by employees. Based on our recent review, we made comprehensive adjustments to our health-related benefits programs, which improved the cost and quality of coverage. We significantly increased the number of employee meetings to provide education and encourage individuals to maximize the value of benefits offered, resulting in an overall increase in participation and positive feedback from employees.

In 2022, we implemented improvements to our 401(k) plan with a focus on improving plan structure, allowing for immediate vesting of employer’s contributions, reducing program administration, providing employee education and increasing plan participation. We also implemented an hourly bonus structure in 2022 to provide greater reward and recognition and improve employee retention. For hydraulic fracturing field employees and related field support positions, a performance element was included to drive key operating metrics.

Availability of Filings
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), are made available free of charge on our internet website at www.propetroservices.com, as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the SEC. The SEC maintains an internet site that contains our reports, proxy and information statements and our other SEC filings. The address of that website is www.sec.gov. Please note that information contained on our website, whether currently posted or posted in the future, is not a part of this Annual Report or the documents incorporated by reference in this Annual Report.
10



Item 1A.    Risk Factors.
The following is a description of significant factors that could cause actual results to differ materially from those contained in forward-looking statements made in this Annual Report and presented elsewhere by management from time to time. Such factors may have a material adverse effect on our business, financial condition and results of operations. It is not possible to predict or identify all such factors. Consequently, you should not consider any such list to be a complete statement of all our potential risks or uncertainties. Due to these, and other factors, past performance should not be considered an indication of future performance.
Risks Inherent in Our Business and Industry
Our business and financial performance depends on the historically cyclical oil and natural gas industry and particularly on the level of capital spending and exploration and production activity within the United States and in the Permian Basin, and a decline in prices for oil and natural gas may cause fluctuation in operating results or otherwise have an adverse effect on our revenue, cash flows, profitability and growth.
Demand for most of our services depends substantially on the level of capital expenditures in the Permian Basin by companies in the oil and natural gas industry. As a result, our operations are dependent on the levels of capital spending and activity in oil and gas exploration, development and production. Demand for our services is largely dependent on oil and natural gas prices, and our customers’ completion budgets and rig count. Prolonged low oil and gas prices would generally depress the level of oil and natural gas exploration, development, production, and well completion activity and would result in a corresponding decline in the demand for the completion services that we provide. Historically, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. WTI oil price declined significantly in 2015 and 2016 to approximately $30 per barrel, but subsequently recovered in 2017. Furthermore, in March 2020, WTI oil price declined to a low of approximately $20 per barrel and then subsequently recovered. The average WTI oil prices per barrel were approximately $94, $68 and $39 for the years ended December 31, 2022, 2021 and 2020, respectively. In the last three years, the highly volatile and unpredictable nature of oil and natural gas prices caused a reduction in our customers’ spending and associated drilling and completion activities, which has had and may continue to have an adverse effect on our revenue and cash flows, if WTI oil prices remain highly volatile or decline in the future.
Many factors over which we have no control affect the supply of, and demand for our services, and our customers’ willingness to explore, develop and produce oil and natural gas, and therefore, influence prices for our services, including:
the severity and duration of world health events, including the COVID-19 pandemic, related economic repercussions;
the actions by the members of OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;
the domestic and foreign supply of, and demand for, oil and natural gas;
the level of prices, and expectations about future prices, of oil and natural gas;
the level of global oil and natural gas exploration and production;
the cost of exploring for, developing, producing and delivering oil and natural gas;
the supply of and demand for drilling and hydraulic fracturing and wireline equipment, including the supply and demand for lower emissions hydraulic fracturing and wireline equipment;
cost increases and supply chain constraints related to our services;
the expected decline rates of current production;
the price and quantity of foreign imports;
political and economic conditions in oil and natural gas producing countries and regions, including the United States, the Middle East, Africa, South America and Russia;
11



operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;
speculative trading in crude oil and natural gas derivative contracts;
the level of consumer product demand;
the discovery rates of new oil and natural gas reserves;
contractions in the credit market;
the strength or weakness of the U.S. dollar;
available pipeline and other transportation capacity;
the levels of oil and natural gas storage;
weather conditions and other natural disasters;
domestic and foreign tax policy;
domestic and foreign governmental approvals and regulatory requirements and conditions, including tighter emissions standards in the energy industry;
the continued threat of terrorism and the impact of military and other action, including military action in the Middle East;
political or civil unrest in the United States or elsewhere;
technical advances affecting energy consumption;
the proximity and capacity of oil and natural gas pipelines and other transportation facilities;
the price and availability of alternative fuels;
the ability of oil and natural gas producers to raise equity capital and debt financing;
merger and divestiture activity among oil and natural gas producers; and
overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, in 2020, Saudi Arabia and Russia failed to agree on a plan to cut production of oil and gas within OPEC and Russia. Subsequently, Saudi Arabia announced plans to increase production and reduce the prices at which they sell oil. In 2022, Russia launched a large-scale invasion of Ukraine, leading to armed hostilities and imposition of sanctions on Russian economic trades. These events, combined with the COVID-19 pandemic which have impacted the economic activity and disrupted the global supply chain dynamics, have contributed to the unpredictable nature of crude oil prices.
12



The cyclical nature of the oil and natural gas industry may cause our operating results to fluctuate.
We derive our revenues from companies in the oil and natural gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices. We have experienced, and may in the future experience, significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, the decline in and unpredictable nature of oil and gas prices in 2019 and 2020, combined with adverse changes in the capital and credit markets and the COVID-19 pandemic in 2020, caused many exploration and production companies to significantly reduce their 2020 and 2021 capital budgets and drilling activity. This resulted in a significant decline in demand for oilfield services and adversely impacted the prices oilfield services companies can charge for their services. These factors have materially and adversely affected our business, results of operations and financial condition. In addition, a majority of the service revenue we earn is based upon a charge for a relatively short period of time (for example, a day, a week or a month) for the actual period of time the service is provided to our customers. By contracting services on a short‑term basis, we are exposed to the risks of a rapid reduction in market prices and utilization and resulting volatility in our revenues.
The majority of our operations are located in the Permian Basin, making us vulnerable to risks associated with operating in one major geographic area.
Our operations are geographically concentrated in the Permian Basin. For the years ended December 31, 2022, 2021 and 2020, approximately 98.3%, 98.7% and 99.5%, respectively, of our revenues were attributable to our operations in the Permian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in the Permian Basin caused by significant governmental regulation, processing or transportation capacity constraints, market limitations, curtailment of production or interruption of the processing or transportation of oil and natural gas produced from the wells in these areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our operations, we could experience any of the same conditions at the same time, resulting in a relatively greater impact on our revenue than they might have on other companies that have more geographically diverse operations.
The IRA 2022 could accelerate the transition to a low carbon economy and could impose new costs on our customers’ operations.
In August 2022, President Biden signed the IRA 2022 into law. The IRA 2022 provides for hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. These incentives could further accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for oil and gas and consequently adversely affect the business of our customers, thereby reducing demand for our services. In addition, the IRA 2022 imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge. The IRA 2022 amends the federal Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the offshore and onshore petroleum and natural gas production and gathering and boosting source categories. The methane emissions charge will start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. The methane emissions charge could increase our customers’ operating costs and adversely affect their businesses, thereby reducing demand for our services.
The COVID-19 outbreak has negatively impacted, and may continue to negatively impact crude oil prices and demand for our products and services.
The outbreak of COVID-19 has adversely impacted and may continue to adversely impact our operations, the operations of our customers and the global economy, including the worldwide demand for oil and natural gas and the level of demand for our products and services. The COVID-19 pandemic also altered the level of capital spending by oil and gas companies for exploration and production activities and adversely affected the economies and financial markets of many countries resulting in an economic downturn that affected demand for our products and services. In response to the initial outbreak of COVID-19, many state and local jurisdictions imposed quarantines, executive orders and similar government orders and restrictions for their residents to control the spread of COVID-19. Such orders or restrictions resulted in business closures, work stoppages, slowdowns and delays, work-from-home policies, travel restrictions and cancellation of events, among other effects. In an effort to minimize the spread of illness, we and our customers implemented various worksite restrictions as well as quarantining in order to minimize the chances of a potential COVID-19 outbreak.
13



During 2021 and 2022, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. While the prices of and demand for crude oil have recovered, further outbreaks or the emergence of new strains of the COVID-19 virus, could result in the reimposition of domestic and international regulations directing individuals to stay at home, limiting travel, requiring facility closures and imposing quarantines. Widespread implementation of these or similar restrictions could result in commodity price volatility, reduced demand for our products and services, as well as delays in or inability to fulfill our contractual obligations to customers, logistic constraints, increases in our costs, and workforce and raw material shortages. The effects of the COVID-19 pandemic and related economic, business and market disruptions thus could continue and adversely affect us.
Our business may be adversely affected by a deterioration in general economic conditions or a weakening of the broader energy industry.
A prolonged economic slowdown or recession in the United States, adverse events relating to the energy industry or regional, national and global economic conditions and factors, particularly a further slowdown in the exploration and production industry, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased exploration and development spending by our customers, decreased demand for oil and natural gas and decreased prices for oil and natural gas. In 2020, the COVID-19 pandemic and the turmoil between the members of OPEC+ caused oil prices to fall substantially and adversely impacted the global economy; a recurrence of similar events would heighten the risk of a prolonged economic slowdown or recession in the United States.
New technology may cause us to become less competitive.
The oilfield services industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent or other intellectual property protections. As competitors and others use or develop new or comparable technologies in the future, we may lose market share or be placed at a competitive disadvantage. The transition to lower emissions equipment is capital intensive and could require us to convert all our conventional Tier II equipment to lower emissions equipment. If we are unable to quickly transition to lower emissions equipment, the demand for our services could be adversely impacted. For example, many E&P companies, including our customers, are transitioning to a lower emissions operating environment and may require us to invest in equipment with lower emissions profile. Further, we may face competitive pressure to develop, implement or acquire and deploy certain technology improvements at a substantial cost, such as our DuraStim® fleets or the cost of implementing or purchasing a technology like DuraStim® may be substantially higher than anticipated, and we may not be able to successfully implement the DuraStim® fleets or other technologies we may purchase. As of December 31, 2022 we recorded an impairment of $57.5 million on our DuraStim® equipment because they did not meet our expectations and remained idled with no near term plans to deploy the equipment to customers’ wellsites. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and develop and implement new products on a timely basis or at an acceptable cost. We cannot be certain that we will be able to develop and implement new technologies or products on a timely basis or at an acceptable cost. Limits on our ability to develop, effectively use and implement new and emerging technologies could have a material adverse effect on our business, financial condition, prospects or results of operations.
Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms, or at all, which could limit our ability to grow.
The oilfield services industry is capital intensive. In conducting our business and operations, we have made, and expect to continue to make, substantial capital expenditures. Our total capital expenditures incurred were approximately $365.3 million, $165.2 million and $81.2 million during the years ended December 31, 2022, 2021 and 2020. We have historically financed capital expenditures primarily with funding from cash on hand, cash flow from operations, equipment and vendor financing and borrowings under our credit facility. We may be unable to generate sufficient cash from operations and other capital resources to maintain planned or future levels of capital expenditures which, among other things, may prevent us from acquiring new equipment (including equipment with a lower emissions profile) or properly maintaining our existing equipment. Any disruptions or volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. Our borrowing base changed from $102.3 million as of December 31, 2022 to approximately $143.3 million as of February 20, 2023 due to a change in our eligible accounts receivable. If our customer activity levels decline in the future resulting in a decrease in our eligible accounts receivable, our borrowing base could decline. This could put us at a competitive disadvantage or interfere with our growth plans. Further, our actual capital expenditures could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of liquidity we have available, we could be required to seek additional sources of capital, which may include debt financing, joint venture partnerships, sales of assets, offerings of debt or equity securities or other
14



means. We may not be able to obtain any such alternative source of capital. We may be required to curtail or eliminate contemplated activities. If we can obtain alternative sources of capital, the terms of such alternative may not be favorable to us. In particular, the terms of any debt financing may include covenants that significantly restrict our operations. Our inability to grow as planned may reduce our chances of maintaining and improving profitability.
Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, geopolitical issues (including the Russia-Ukraine war), public health crises (including the COVID-19 pandemic), interest rates, inflation, the availability and cost of credit in the United States and foreign financial markets have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, could precipitate an economic slowdown. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. The historically unpredictable nature of oil and natural gas prices, and particularly the volatility over the past two years have caused a reduction in our customers’ spending and associated drilling and completion activities, which had and may continue to have an adverse effect on our revenue and cash flows. If the economic climate in the United States or abroad deteriorates or remains uncertain, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids can be sold, which could affect the ability of our customers to continue operations and adversely impact our results of operations, liquidity and financial condition.
Our indebtedness and liquidity needs could restrict our operations and make us more vulnerable to adverse economic conditions.
Our existing and future indebtedness, whether incurred in connection with acquisitions, operations or otherwise, may adversely affect our operations and limit our growth, and we may have difficulty making debt service payments on such indebtedness as payments become due. Our level of indebtedness may affect our operations in several ways, including the following:
•    increasing our vulnerability to general adverse economic and industry conditions;
•    the covenants that are contained in the agreements governing our indebtedness could limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;
•    our debt covenants could also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
•    any failure to comply with the financial or other debt covenants, including covenants that impose requirements to maintain certain financial ratios, could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable;
•    our level of debt could impair our ability to obtain additional financing, or obtain additional financing on favorable terms in the future for working capital, capital expenditures, acquisitions or other general corporate purposes; and
•    our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.
Restrictions in our ABL Credit Facility and any future financing agreements may limit our ability to finance future operations or capital needs or capitalize on potential acquisitions and other business opportunities.
The operating and financial restrictions and covenants in our credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our ABL Credit Facility restricts or limits our ability to:
grant liens;
incur additional indebtedness;
engage in a merger, consolidation or dissolution;
enter into transactions with affiliates;
15



sell or otherwise dispose of assets, businesses and operations;
materially alter the character of our business as currently conducted; and
make acquisitions, investments and capital expenditures.
Furthermore, our ABL Credit Facility contains certain other operating and financial covenants. Our ability to comply with the covenants and restrictions contained in the ABL Credit Facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our ABL Credit Facility, a significant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. Further, our borrowing base, as redetermined monthly, is tied to 85.0% to 90.0% of eligible accounts receivable. Changes to our operational activity levels or customer concentration levels have an impact on our total eligible accounts receivable, which could result in significant changes to our borrowing base and therefore our availability under our ABL Credit Facility. For example, our borrowing base changed from $102.3 million as of December 31, 2022 to approximately $143.3 million as of February 20, 2023 due to a change in our eligible accounts receivable. If our customer activity declines in the future, our borrowing base could decline. If our borrowing base is reduced below the amount of our outstanding borrowings, we will be required to repay the excess borrowings immediately on demand by the lenders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our ABL Credit Facility or any new indebtedness could have similar or greater restrictions. Please read "Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facility and Other Financing Arrangements."
We may incur debt and our indebtedness could adversely affect our operations and financial condition.
Our business is capital intensive and we may seek to raise debt capital to fund our business and growth strategy. Indebtedness could have negative consequences that could materially and adversely affect our business, financial condition, results of operations, cash flows and prospects, such as:
requiring us to dedicate a substantial portion of our cash flow from operating activities to payments on our indebtedness, thereby reducing the availability of cash flow to fund working capital, capital expenditures, research and development efforts, potential strategic acquisitions and other general corporate purposes;
limiting our ability to obtain additional financing to fund growth, working capital or capital expenditures, or to fulfill debt service requirements or other cash requirements;
increasing our vulnerability to economic downturns and changing market conditions; and
placing us at a competitive disadvantage relative to competitors that have less debt.
Furthermore, interest rates on future indebtedness could be higher than current levels, causing our financing costs to increase accordingly. In addition, LIBOR and other “benchmark” rates are subject to ongoing national and international regulatory scrutiny and reform. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of June 2023 for US dollars setting. At this time, no consensus exists as to what rate or rates may become acceptable alternatives to LIBOR and we are unable to predict the effect of any such alternatives on our business and results of operations. However, if LIBOR is phased out without a replacement benchmark, our only option under the ABL Credit Facility will be to borrow at the Base Rate (as defined in the ABL Credit Facility) until an alternative benchmark rate is selected. Changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on the price of our shares, our ability to issue equity or incur debt.
We may record losses or impairment charges related to goodwill and long-lived assets including intangible assets.
Changes in future market conditions and prolonged periods of low utilization, changes in technology or the sale of assets below their carrying value may cause us to experience losses in our results of operations. These events could result in the recognition of impairment charges or losses from asset sales that negatively impact our financial results. Significant impairment charges or losses from asset sales as a result of a decline in market conditions or otherwise could have a material adverse effect on our results of operations in future periods. For example, in 2021, we recorded loss on disposal of asset $3.5 million in connection with the sale of our two turbines. In 2022, we recorded impairment charges of $57.5 million in connection with our DuraStim®
16



equipment, which remained idled with no near term plans to deploy the equipment to customers’ wellsites. If oil and natural gas prices trade at depressed price levels as experienced in the first half of 2020, and our equipment remains idle or under-utilized, the estimated fair value of such equipment may decline, which will result in additional impairment expense in the future.

Our operations are subject to unforeseen interruptions and hazards inherent in the oil and natural gas industry, for which we may not be adequately insured and which could cause us to lose customers and substantial revenue.
Our operations are exposed to the risks inherent to our industry, such as equipment defects, vehicle accidents, worksite injuries to our or third-party personnel, fires, explosions, blowouts, surface cratering, uncontrollable flows of gas or well fluids, pipe or pipeline failures, abnormally pressured formations and various environmental hazards, such as oil spills and releases of, and exposure to, hazardous substances. For example, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including hydrochloric acid and other chemical additives. In addition, our operations are exposed to potential natural disasters, including blizzards, tornadoes, storms, floods, other adverse weather conditions and earthquakes. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean‑up responsibilities, regulatory investigations and penalties or other damage resulting in curtailment or suspension of our operations or the loss of customers. The cost of managing such risks may be significant. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our environmental or safety record as unacceptable, which could cause us to lose customers and substantial revenues.
Our insurance may not be adequate to cover all losses or liabilities we may suffer. We are also self-insured up to $10 million per occurrence for certain losses arising from or attributable to fire and/or explosion at wellsites. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In addition, sub‑limits have been imposed for certain risks. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we are not fully insured, it could have a material adverse effect on our business, results of operations and financial condition. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position.
Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean‑up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the "occurrence" to our insurance company within the time frame required under our insurance policy. In addition, these policies do not provide coverage for all liabilities, and the insurance coverage may not be adequate to cover claims that may arise, or we may not be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
A terrorist attack, armed conflict or political or civil unrest could harm our business.
Terrorist activities, anti‑terrorist efforts, other armed conflicts and political or civil unrest could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if pipelines, production facilities, processing plants, refineries or transportation facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our services. Terrorist activities, the threat of potential terrorist activities, political or civil unrest and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.
We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.
We operate with most of our customers under master service agreements ("MSAs"). We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. Our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts.
17



Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer‑owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in us being named as a defendant in lawsuits asserting large claims. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and process and record operational and accounting data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings indicating that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary information, personal information and other data, or other disruption of our business operations. In addition, certain cyber incidents, such as unauthorized surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks, including cyberattacks, may not be sufficient and may not protect against or cover all of the losses (including potential reputational loss) we may experience as a result of the realization of such risks. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate the effects of cyber incidents.
We may grow through acquisitions and our failure to properly plan and manage those acquisitions may adversely affect our performance.
We have completed and may in the future pursue, asset acquisitions or acquisitions of businesses. Any acquisition of assets or businesses involves potential risks, including the failure to realize expected profitability, growth or accretion; environmental or regulatory compliance matters or liability; title or permit issues; the incurrence of significant charges, such as impairment of goodwill, property and equipment or intangible assets or restructuring charges; and the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate. The process of upgrading acquired assets to our specifications and integrating acquired assets or businesses may also involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a significant amount of time and resources and may divert management’s attention from existing operations or other priorities. For example, in 2022, we consummated the Silvertip Acquisition, and we are in the process of fully integrating all parts of the acquired business into our operations.
We must plan and manage any acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. Any failure to manage acquisitions effectively or integrate acquired assets or businesses into our existing operations successfully, or to realize the expected benefits from an acquisition or minimize any unforeseen operational difficulties, could have a material adverse effect on our business, financial condition, prospects or results of operations.
We may be adversely affected by the effects of inflation.
The U.S. inflation rate has been steadily increasing since 2021 and through 2022. Inflation in wages, materials, parts, equipment and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure, particularly if we are unable to achieve commensurate increases in the prices we charge our customers for our products and services. In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, supply shortages, increased costs of labor, weakening exchange rates and other similar effects. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates multiple times in 2022 and the U.S. Federal Reserve has indicated its intention to continue to raise benchmark interest rates into 2023 in an effort to curb inflationary pressure on the costs of goods and services across the U.S., which could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial and operating results of our business. To the extent elevated inflation remains,
18



we may experience further cost increases for our operations, including labor costs and equipment. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to timely pass-through the cost increases to our customers, would negatively impact our business, financial condition and results of operations.
Risks Related to Customers, Suppliers and Competition
Reliance upon a few large customers may adversely affect our revenue and operating results.
The majority of our revenue is generated from our hydraulic fracturing services. Due to the large percentage of our revenue historically derived from our hydraulic fracturing services with recurring customers and the limited availability of our fracturing units, we have had some degree of customer concentration. Our top ten customers represented approximately 91.2%, 91.4% and 97.3% of our consolidated revenue for the years ended December 31, 2022, 2021 and 2020, respectively. It is likely that we will depend on a relatively small number of customers for a significant portion of our revenue in the future. If a major customer fails to pay us, revenue would be impacted and our operating results and financial condition could be harmed.
Additionally, if we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels and such loss could have an adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels. One customer, Pioneer, accounted for 33.1% of our revenue for the year ended December 31, 2022. The revenue generated from our relationship with Pioneer is largely derived from the A&R Pressure Pumping Services Agreement, which reduced our committed fleet to six through December 31, 2022. On October 31, 2022, we entered into the Fleet One Agreement and the Fleet Two Agreement with Pioneer to provide two committed fleets with terms ranging from eight to twelve month periods. Each agreement was effective January 1, 2023 and is subject to certain termination and release rights. In February 2023, Pioneer provided the Company notice (i) stating that Pioneer intended to release Fleet Two effective upon the completion of operations on the pad where the performance of Services (as defined in the Fleet Two Agreement) is in progress on May 12, 2023 and (ii) requesting that the Company agree to the termination of the Fleet Two Agreement as of the Release Date. The Company agreed with such request, and, as a result, the Fleet Two Agreement will be terminated as of the Release Date. If Pioneer elects to terminate the remaining committed fleet and we are unable to redeploy such fleet to another customer, it could have a material adverse effect on our financial condition, results of operations and cash flows. See "Part I, Item 1. Business — Customers" for further information regarding the agreements with Pioneer.
We face significant competition that may cause us to lose market share, and competition in our industry has intensified during the industry downturn.
The oilfield services industry is highly competitive and has relatively few barriers to entry. The principal competitive factors impacting sales of our services are price, reputation and technical expertise, equipment and service quality and health and safety standards. The market is also fragmented and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can. For instance, our larger competitors may offer services at below‑market prices or bundle ancillary services at no additional cost to our customers. We compete with large national and multi‑national companies that have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis.
Some jobs are awarded on a bid basis, which further increases competition based on price. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment may be further intensified by tighter emissions standards in the energy industry and mergers and acquisitions among oil and natural gas companies or other events that have the effect of reducing the number of available customers. As a result of competition, we may lose customers or customer work and lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. The amount of equipment available may exceed demand, which could result in active price competition. In addition, some E&P companies have commenced completing their wells using their own hydraulic fracturing equipment and personnel. Any increase in the development and utilization of in‑house fracturing capabilities by our customers could decrease the demand for our services and have a material adverse impact on our business.
Pressure on pricing for our services resulting from the industry downturn has impacted, and may continue to impact, our ability to maintain utilization and pricing for our services or implement price increases. During periods of declining pricing for our
19



services, we may not be able to reduce our costs accordingly, which could further adversely affect our results of operations. Also, we may not be able to successfully increase prices without adversely affecting our utilization levels. The inability to maintain our utilization and pricing levels, or to increase our prices as costs increase, could have a material adverse effect on our business, financial condition and results of operations.
Furthermore, competition among oilfield services and equipment providers is affected by each provider’s reputation for safety and quality. We cannot assure that we will be able to maintain our competitive position.
We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our business, results of operations and financial condition.
We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re‑market or otherwise use the production could have a material adverse effect on our business, results of operations and financial condition. In weak economic environments, we may experience increased delays and failures to pay due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets or other sources of capital. The unpredictable nature of oil and gas prices in recent years and the economic disruption from the COVID-19 pandemic may have negatively impacted the financial condition and liquidity of some of our customers, and future declines or continued volatility could impact their ability to meet their financial obligations to us. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, results of operations, and financial condition.
Our business depends upon the ability to obtain specialized equipment, parts and key raw materials, including sand and chemicals, from third‑party suppliers, and we may be vulnerable to delayed deliveries and future price increases.
We purchase specialized equipment, parts and raw materials (including, for example, frac sand, chemicals and fluid ends) from third party suppliers and affiliates. In some cases, our customers are responsible for supplying necessary raw materials (including frac sand), parts and/or equipment. At times during the business cycle, there is a high demand for hydraulic fracturing and other oilfield services and extended lead times to obtain equipment and raw materials needed to provide these services. For example, in 2021 and 2022, we have seen significant disruption in supply chains around the world caused by the COVID-19 pandemic that have impacted our operations. Should our current suppliers (or our customers’ suppliers where applicable) be unable or unwilling to provide the necessary equipment, parts or raw materials or otherwise fail to deliver the products timely and/or in the quantities required, any resulting delays in the provision of our services could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, future price increases for this type of equipment, parts and raw materials could negatively impact our ability to purchase new equipment, to update or expand our existing fleets, to timely repair equipment in our existing fleets or meet the current demands of our customers.
We may be required to pay fees to certain of our sand suppliers based on minimum volumes under long-term contracts regardless of actual volumes received.
We enter into purchase agreements with sand suppliers (the "Sand Suppliers") to secure supply of sand in the normal course of our business. The agreements with the Sand Suppliers require that we purchase minimum volume of sand, based primarily on a certain percentage of our sand requirements from our customers or in certain situations based on predetermined fixed minimum volumes, otherwise certain penalties (shortfall fees) may be charged. The shortfall fee represents liquidated damages and is either a fixed percentage of the purchase price for the minimum volumes or a fixed price per ton of unpurchased volumes. Our current agreements with Sand Suppliers expire at different times prior to December 31, 2025.
Disruption of our supply chain could adversely impact our ability to provide our services.
Our suppliers use multiple forms of transportation to bring their products to market, including truck, ocean and air-cargo shipments. Disruption to the timely supply of raw materials, parts and finished goods or increases in the cost of transportation services, including due to general inflationary pressures, cost of fuel and labor, labor disputes, governmental regulation or governmental restrictions limiting specific forms of transportation, could have an adverse effect on our ability to provide our services, which would adversely affect our results of operations, cash flows and financial position
20



Risks Related to Employees
We rely on a few key employees whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, such as our Chief Executive Officer, President and Chief Operating Officer, Chief Financial Officer, Chief Accounting Officer and General Counsel could disrupt our operations. We do not maintain "key person" life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
If we are unable to employ a sufficient number of skilled and qualified workers, our capacity and profitability could be diminished and our growth potential could be impaired.
The delivery of our services requires skilled and qualified workers with specialized skills and experience who can perform physically demanding work. As a result of the volatility of the oilfield services industry and the demanding nature of the work, workers may choose to pursue employment in fields that offer a less challenging work environment at wage rates that are competitive. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled workers. As a result of the COVID-19 pandemic and the physical nature of our operations, we have experienced difficulties in attracting and retaining skilled workers. If demand for our services increases, we may experience difficulty in hiring or re-hiring skilled and unskilled workers in the future to meet that demand. At times, the demand for skilled workers in our geographic areas of operations is high, and the supply is limited. As a result, competition for experienced oilfield services personnel is intense, and we face significant challenges in competing for crews and management with large and well‑established competitors. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. Furthermore, if we are unable to adjust wages to account for rapidly rising inflationary cost, there could be a reduction in the available skilled labor force we could attract or retain. If any of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
Risks Related to Regulatory Matters
We are subject to environmental laws and regulations, and future compliance, claims, and liabilities relating to such matters may have a material adverse effect on our results of operations, financial position or cash flows.
The nature of our operations, including the handling, storing, transporting and disposing of a variety of fluids and substances, including hydraulic fracturing fluids, which can contain substances such as hydrochloric acid, and other regulated substances, air emissions and wastewater discharges exposes us to some risks of environmental liability, including the release of pollutants from oil and natural gas wells and associated equipment to the environment. The cost of compliance with these laws can be significant. Failure to properly handle, transport or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to substantial liability for administrative, civil and criminal penalties, cleanup and site restoration costs and liability associated with releases of such materials, damages to natural resources and other damages, as well as potentially impair our ability to conduct our operations. Such liability is commonly on a strict, joint and several liability basis, without regard to fault. Liability may be imposed as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Neighboring landowners and other third parties may file claims against us for personal injury or property damage allegedly caused by the release of pollutants into the environment. Environmental laws and regulations have changed in the past, and they may change in the future and become more stringent. For example, following the election of President Biden, President Biden has made climate change a focus of his administration. For more information, see our risk factor titled, “Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide.” Separately, current and future claims and liabilities may have a material adverse effect on us because of potential adverse outcomes, defense costs, diversion of management resources, unavailability of insurance coverage and other factors. The ultimate costs of these liabilities are difficult to determine and may exceed any reserves we may have established. If existing environmental requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.
Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide.
21



The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate future GHG emissions. As a result, our operations as well as the operations of our oil and natural gas exploration and production customers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level, though recently passed laws such as the IRA 2022 advance numerous climate-related objectives. Additionally, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of certain pollutants from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the Department of Transportation ("DOT"), implementing GHG emissions limits on vehicles manufactured for operation in the United States. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, subsequently, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb new source and OOOOc first-time existing source of standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance to include leak detection using optical gas imaging and subsequent repair equipment, and reduction of emissions by 95% through capture and control systems. In November 2022, the EPA published a supplemental methane proposal, which, among other items, sets forth specific revisions strengthening the first nationwide emission guidelines for states to limit methane emissions from existing crude oil and natural gas facilities. The proposal also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a "super-emitter" response program to timely mitigate emissions events as detected by governmental agencies or qualified third parties, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. The proposal is currently subject to public comment and is expected to be finalized in 2023; however, it is likely that these requirements will be subject to legal challenge. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas such as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored "Paris Agreement," requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined Contributions ("NDCs") every five years after 2020. Following President Biden’s executive order in January 2021, the United States rejoined the Paris Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below 2005 levels by 2030. Additionally, at the 26th Conference of the Parties ("COP26") in Glasgow in November 2021, the United States and the European Union jointly announced the launch of the Global Methane Pledge; an initiative committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including "all feasible reductions" in the energy sector. At COP27 in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The US also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future. However, the impacts of these actions are unclear at this time.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored "Paris Agreement," requires member states to submit non-binding, individually-determined reduction goals known as NDC’s every five years after 2020. Following President Biden’s executive order in January 2021, the United States rejoined the Paris Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below 2005 levels by 2030. Additionally, at the COP26 in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge; an initiative committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. However, the impacts of these actions are unclear at this time.
22



Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate-change-related pledges made by certain candidates for public office. On January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and an increased emphasis on climate-related risk across government agencies and economic sectors. The executive order also suspends the issuance of new leases for oil and gas development on federal land; for more information, see our risk factor titled "Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays."
Other actions that the Biden Administration may take include the imposition of more restrictive requirements for the development of pipeline infrastructure or liquefied natural gas export facilities, or more restrictive GHG emissions limitations for oil and gas facilities. Litigation risks are also increasing as a number of parties have sought to bring suit against certain oil and natural gas companies operating in the United States in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or that such companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts to their investors or customers.
There are also increasing financial risks for companies in the fossil fuel sector as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero ("GFANZ") announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced that it has joined the Network for Greening the Financial System ("NGFS"), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, the Federal Reserve has issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. In January 2023, the Federal Reserve launched a pilot climate scenario analysis exercise, with six of the United States’ largest banks participating to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. Additionally, the United States Securities and Exchange Commission has announced a proposed rule that would require climate disclosures, including registrants’ Scope 1 and 2 emissions and, in some cases, Scope 3 emissions. Although the final form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements. We also cannot predict how financial institutions and investors might consider any information disclosed under the final rule when making investment decisions, and as a result it is possible that we could face increases with respect to the costs of, or restrictions imposed on, our access to capital.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our services and products. Additionally, political, litigation and financial risks may result in our oil and natural gas customers restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our services and products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operations.
Moreover, climate change may result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in the meteorological and hydrological patterns, that could adversely impact us, our customers’ and our suppliers’ operations. Such physical risks may result in damage to our customers’ facilities or otherwise adversely impact our operations, such as if facilities are subject to water use curtailments in response to drought, or demand for our customers’ products, such as to the extent warmer winters reduce the demand for energy for heating purposes, which may ultimately reduce demand for the products and services we provide. Such physical risks may also impact our suppliers, which may adversely affect our ability to provide our products and services. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured.
23



Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Our hydraulic fracturing operations are a significant component of our business, and it is an important and common practice that is used to stimulate production of hydrocarbons, particularly oil and natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has previously issued a series of rules under the CAA that establish new emission control requirements for emissions of volatile organic compounds and methane from certain oil and natural gas production and natural gas processing operations and equipment. Separately, the BLM finalized a rule governing hydraulic fracturing on federal lands but this rule was subsequently rescinded. Although several of these rulemakings have been rescinded, modified or subjected to legal challenges, new or more stringent regulations may be promulgated by the Biden Administration. For example, the BLM recently proposed a rule that would limit flaring from well sites on federal lands, as well as allow the delay or denial of permits if BLM finds that an operator’s methane waste minimization plan is insufficient. In January 2021, President Biden issued an executive order suspending new leasing activities, but not operations under existing leases, for oil and gas exploration and production on non-Indian federal lands 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. Although the leasing pause was effectively halted by a permanent injunction in August 2022, in response to the executive order, the DOI issued a report recommending various changes to the federal leasing program, though many such changes would require Congressional action. As a result, we cannot predict the final scope of regulations or restrictions that may apply to oil and gas operations on federal lands. However, any regulations that ban or effectively ban such operations may adversely impact demand for our products and services. Further, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress. Several states and local jurisdictions in which we or our customers operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.
Federal and state governments have also investigated whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for wastewater disposal wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In particular, the Oklahoma Corporation Commission released well completion seismicity guidelines for operators in the SCOOP and STACK require hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division has previously issued an order limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state. The TRRC has adopted similar rules and, in September 2021, issued a notice to disposal well operators in the Gardendale Seismic Response Area near Midland, Texas to reduce daily injection volumes following multiple earthquakes above a 3.5 magnitude over an 18 month period. The notice also required disposal well operators to provide injection data to TRRC staff to further analyze seismicity in the area. Subsequently, the TRRC ordered the indefinite suspension of all deep oil and gas produced water injection wells in the area, effective December 31, 2021. The Gardendale Seismic Response area has since been expanded in response to an additional earthquake in December 2022, covering 17 additional wells. While we cannot predict the ultimate outcome of these actions, any action that temporarily or permanently restricts the availability of disposal capacity for produced water or other oilfield fluids may increase our customers’ costs or require them to suspend operations, which may adversely impact demand for our products and services
Increased regulation of hydraulic fracturing and related activities could subject us and our customers to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, and plugging and abandonment requirements. New requirements could result in increased operational costs for us and our customers, and reduce the demand for our services.
24



Increasing trucking regulations may increase our costs and negatively impact our results of operations.
In connection with our business operations, including the transportation and relocation of our hydraulic fracturing equipment and shipment of frac sand, we operate trucks and other heavy equipment. As such, we operate as a motor carrier in providing certain of our services and therefore are subject to regulation by the DOT and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, financial reporting and review of certain mergers, consolidations and acquisitions, and transportation of hazardous materials. Our trucking operations are subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements prescribed by the DOT. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Matters such as the weight and dimensions of equipment are also subject to federal and state regulations. From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Certain motor vehicle operators require registration with the DOT. This registration requires an acceptable operating record. The DOT periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria that could result in a suspension of operations.
Increased attention to environmental, social and governance ("ESG") matters, conservation measures, commercial development and technological advances could reduce demand for oil and natural gas and our services.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, increased attention to climate change and other ESG matters, and technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas, resulting in reduced demand for oilfield services. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
The commercial development of economically‑viable alternative energy sources and related products (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could have a similar effect. The IRA 2022 appropriates significant federal funding for renewable energy initiatives, which could accelerate the use and commercial viability of alternative energy sources and decrease demand for oil and natural gas. The IRA 2022 has incentivized the further development of and investment in clean energy through the use of tax credits, and future legislation could expand these benefits for alternative energy sources. In addition, certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development, including the allowance of percentage depletion for oil and natural gas properties, may be eliminated as a result of proposed legislation. Any future decreases in the rate at which oil and natural gas reserves are discovered or developed, whether due to the passage of legislation, increased governmental regulation leading to limitations, or prohibitions on exploration and drilling activity, including hydraulic fracturing, or other factors, could have a material adverse effect on our business and financial condition, even in a stronger oil and natural gas price environment.
Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, certain statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Additionally, we may announce various targets or product and service offerings in an attempt to improve our ESG profile. However, we cannot guarantee that we will be able to meet any such targets or that such targets or offerings will have the intended results on our ESG profile, including but not limited to as a result of unforeseen costs, consequences or technical difficulties associated with such targets or offerings. Also, despite any voluntary actions, we may receive pressure from certain investors, lenders or other groups to adopt more aggressive climate or other ESG-related goals or policies, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform
25



their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.
Certain of our completion services, particularly our hydraulic fracturing services, are substantially dependent on the availability of water. Restrictions on our or our customers’ ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of unconventional shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Over the past several years, certain of the areas in which we and our customers operate have experienced extreme drought conditions and competition for water in such areas is growing. In addition, some state and local governmental authorities have begun to monitor or restrict the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply. For instance, some states require E&P companies to report certain information regarding the water they use for hydraulic fracturing and to monitor the quality of groundwater surrounding some wells stimulated by hydraulic fracturing. Generally, our water requirements are met by our customers from sources on or near their sites, but there is no assurance that our customers will be able to obtain a sufficient supply of water from sources in these areas. Our or our customers’ inability to obtain water from local sources or to effectively utilize flowback water could have an adverse effect on our financial condition, results of operations and cash flows.
Risks Related to our Tax Matters
Our ability to use our net operating loss carryforwards may be limited.
The Tax Cuts and Jobs Act (the "TCJA") included a reduction to the maximum deduction allowed for net operating losses generated in tax years after December 31, 2017, and the elimination of carrybacks of net operating losses. Under the Coronavirus Aid, Relief, and Economic Security Act, or the CARES Act, which modified the TCJA, U.S. federal net operating loss carryforwards ("NOLs") generated in taxable periods beginning after December 31, 2017, may be carried forward indefinitely, but the deductibility of such NOLs in taxable years beginning after December 31, 2020, is limited to 80% of taxable income. As of December 31, 2022, we had approximately $421.7 million of U.S. federal NOLs, some of which will begin to expire in 2035. Approximately $219.5 million of our U.S. federal NOLs relate to pre-2018 periods. As of December 31, 2022, our state net operating losses were approximately $50.4 million and will begin to expire in 2024.
Utilization of these NOLs depends on many factors, including our future income, which cannot be assured. In addition, Section 382 ("Section 382") of the Internal Revenue Code of 1986, as amended (the "Code"), generally imposes an annual limitation on the amount of taxable income that may be offset by NOLs when a corporation has undergone an "ownership change" (as determined under Section 382). Generally, a change of more than 50% in the ownership of a corporation’s stock, by value, over a three‑year period constitutes an ownership change for U.S. federal income tax purposes. Any unused annual limitation may, subject to certain limitations, be carried over to later years. We may experience ownership changes, which may result in annual limitation under Section 382 determined by multiplying the value of our stock at the time of the ownership change by the applicable long‑term tax‑exempt rate as defined in Section 382, increased under certain circumstances as a result of recognizing built‑in gains in our assets existing at the time of the ownership change. The limitations arising from ownership changes may prevent utilization of our NOLs prior to their expiration. Future ownership changes or regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows if we attain profitability.
Risks Inherent to an Investment in our Common Stock
We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act ("Section 404"). If we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.
We are required to comply with certain provisions of Section 404, which requires that we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm issue an attestation report on such internal control.
If we or our auditors identify and report material weaknesses in our internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to
26



lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows.
Certain provisions of our certificate of incorporation, and bylaws, as well as Delaware law, may discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our certificate of incorporation authorizes our board of directors (the "Board") to issue preferred stock without shareholder approval. If our Board elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our shareholders, including:
limitations on the removal of directors;
limitations on the ability of our shareholders to call special meetings;
advance notice provisions for shareholder proposals and nominations for elections to the Board to be acted upon at meetings of shareholders;
providing that the Board is expressly authorized to adopt, or to alter or repeal our bylaws; and
establishing advance notice and certain information requirements for nominations for election to our Board or for proposing matters that can be acted upon by shareholders at shareholder meetings.
Our business could be negatively affected as a result of the actions of activist shareholders.
Publicly traded companies have increasingly become subject to campaigns by investors seeking to increase shareholder value by advocating corporate actions such as financial restructuring, increased borrowing, special dividends, stock repurchases, sales of assets or even sale of the entire company. Given our shareholder composition and other factors, it is possible such shareholders or future activist shareholders may attempt to effect such changes or acquire control over us. Responding to proxy contests and other actions by such activist shareholders or others in the future would be costly and time-consuming, disrupt our operations and divert the attention of our Board and senior management from the pursuit of business strategies, which could adversely affect our results of operations and financial condition. Additionally, perceived uncertainties as to our future direction as a result of shareholder activism or changes to the composition of the Board may lead to the perception of a change in the direction of our business, instability or lack of continuity which may be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel. If customers choose to delay, defer or reduce transactions with us or transact with our competitors instead of us because of any such issues, then our business, financial condition, revenues, results of operations and cash flows could be adversely affected.
Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to pursue actions in another judicial forum for disputes with us or our directors, officers, employees or agents.
Our certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our shareholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the "DGCL"), our certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.
The exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act or the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.
27



The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings, and it is possible that a court could find the choice of forum provisions contained in our certificate of incorporation to be inapplicable or unenforceable, including with respect to claims arising under the U.S. federal securities laws.
Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation regarding exclusive forum. This choice of forum provision may limit a shareholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
The market price of our common stock is subject to volatility.
The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading of our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our limited trading volume, the concentration of holdings or our common stock, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets, volatility in oil and gas prices and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this report. Significant sales of our common stock, or the expectation of these sales, by significant shareholders, officers or directors could materially and adversely affect the market price of our common stock.
There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.
We are not restricted from issuing additional common stock, including securities that are convertible into or exchangeable for, or that represent a right to receive, common stock. In addition, we may issue common stock as consideration in future mergers and acquisitions, as we did in the Silvertip Acquisition. Any issuance of additional shares of our common stock or convertible securities will dilute the ownership interest of our common stockholders. Sales of a substantial number of shares of our common stock or other equity-related securities in the public market, or the perception that these sales could occur, could depress the market price of our common stock and impair our ability to raise capital through the sale of additional equity securities. We cannot predict the effect that future sales of our common stock or other equity-related securities would have on the market price of our common stock.
28



Item 1B. Unresolved Staff Comments.
None.
Item 2.     Properties
Our corporate headquarters is located at 1706 S. Midkiff, Midland, Texas 79701. In addition to our headquarters, we also own and lease other properties that are used for field offices, yards or storage in the Permian Basin. We believe that our facilities are adequate for our current operations.
Item 3.     Legal Proceedings.
Disclosure concerning legal proceedings is incorporated by reference to "Note 17. Commitments and Contingencies— Contingent Liabilities" of our Consolidated Financial Statements contained in this Annual Report.
From time to time, we may be subject to various other legal proceedings and claims incidental to or arising in the ordinary course of our business.
Item 4.     Mine and Safety Disclosures
None.

29


PART II
Item 5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
On March 22, 2017, we consummated our initial public offering ("IPO") of our common stock at a price of $14.00 per share. Our common stock is traded on the New York Stock Exchange under the symbol "PUMP."
Holders
As of December 31, 2022, there were 114,515,008 shares of common stock outstanding, held of record by six holders. The number of record holders of our common stock does not include Depository Trust Company participants or beneficial owners holding shares through nominee names.
Dividend
We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business and repay borrowings under our ABL Credit Facility, if any. Our future dividend policy is within the discretion of our Board and will depend upon then‑existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our Board may deem relevant. In addition, our ABL Credit Facility places certain restrictions on our ability to pay cash dividends.
Performance Graph
The annual changes for the periods shown in the following graph are based on the assumption that $100 had been invested in our common stock, the Russell 2000 Index ("Russell 2000") and a self-constructed peer group index of comparable companies ("Peer Group") on March 17, 2017 (the first trading date of our common stock), and that all dividends were reinvested at the closing prices of the dividend payment dates. The relevant companies included in our Peer Group consists of Liberty Energy Inc., Nextier Oilfield Solutions Inc., RPC, Inc., Calfrac Well Services Ltd., Patterson-UTI Energy, Inc. and Mammoth Energy Services, Inc. The total cumulative dollar returns shown on the graph represent the value that such investments would have had on the last trading date of 2022. The calculations exclude trading commissions and taxes. The stock price performance on the following graph and table is not necessarily indicative of future stock price performance.

30


pump-20221231_g1.jpg
Date Peer Group Russell 2000 ProPetro Holding Corp.
12/31/2017 $ 100.0  $ 100.0  $ 100.0 
12/31/2018 $ 45.5  $ 89.0  $ 61.1 
12/31/2019 $ 32.8  $ 111.7  $ 55.8 
12/31/2020 $ 20.0  $ 134.0  $ 36.7 
12/31/2021 $ 24.2  $ 153.9  $ 40.2 
12/31/2022 $ 48.6  $ 122.4  $ 51.4 









31


Item 6.     [Reserved]

32



Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
You should read the following discussion and analysis of our financial condition and results of operations together with our audited consolidated financial statements and the related notes included in this Annual Report. Some of the information contained in this discussion and analysis or set forth elsewhere in this Annual Report, including information with respect to our plans and strategy for our business and related financing, includes forward‑looking statements that involve risks and uncertainties. You should read the "Risk Factors" section of this Annual Report for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward‑looking statements contained in the following discussion and analysis.
Basis of Presentation
This discussion of our results omits our results of operations and cash flows for the year ended December 31, 2020 and the comparison of our results of operations for the years ended December 31, 2021 and 2020, which may be found in our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022.
Unless otherwise indicated, references in this "Management’s Discussion and Analysis of Financial Condition and Results of Operations" to "ProPetro Holding Corp.," "the Company," "we," "our," "us" or like terms refer to ProPetro Holding Corp. and its subsidiaries.
Overview
Our Business
We are a leading integrated oilfield services company, located in Midland, Texas, focused on providing innovative hydraulic fracturing, wireline and other complementary oilfield completion services to leading upstream oil and gas companies engaged in the E&P of North American oil and natural gas resources. Our operations are primarily focused in the Permian Basin, where we have cultivated longstanding customer relationships with some of the region’s most active and well‑capitalized E&P companies. The Permian Basin is widely regarded as one of the most prolific oil‑producing areas in the United States, and we believe we are one of the leading providers of completion services in the region.
Our hydraulic fracturing operations account for approximately 89.3% of our total revenues and operations. Our total available hydraulic horsepower ("HHP") in our hydraulic fracturing operations at December 31, 2022 was 1,315,000 HHP, which was comprised of 252,500 HHP of our Tier IV DGB equipment and 1,062,500 HHP of conventional Tier II equipment. Our hydraulic fracturing fleets range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsites. Our equipment has been designed to handle the operating conditions commonly encountered in the Permian Basin and the region’s increasingly high-intensity well completions (including Simul-Frac, which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well. With the industry transition to lower emissions equipment and Simul-Frac, in addition to several other changes to our customers' job designs, we believe that our available capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites. In addition, in September 2021, August 2022 and December 2022, we committed to additional conversions of our Tier II equipment to Tier IV DGB, and purchase of new Tier IV DGB equipment. As such, we entered into conversion and purchase arrangements with our equipment manufacturers for a total of 362,500 HHP of Tier IV DGB equipment and as of December 31, 2022, we have received 192,500 HHP of the converted and new Tier IV DGB equipment and expect to receive the remaining 170,000 HHP by the second quarter of 2023. In August 2022 and December 2022, we entered into three-year electric fleet leases for a total of four fleets with 60,000 HHP per fleet. We expect to take delivery of the electric fleets at different times during the second half of 2023.
On November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip Completion Services Operating, LLC, which provides wireline perforation and ancillary services solely in the Permian Basin in exchange for 10.1 million shares of our common stock valued at $106.7 million, $30.0 million of cash, the payoff of $7.2 million of assumed debt, and the payment of certain other closing and transaction costs. At December 31, 2022, we had 23 wireline units available to provide wireline perforation and ancillary services. The Silvertip Acquisition positions the Company as a more resilient and diversified completions-focused oilfield services provider headquartered in the Permian Basin.

Our substantial market presence in the Permian Basin positions us well to capitalize on drilling and completion activity in the region. Primarily, our operational focus has been in the Permian Basin's Midland sub-basin, where our customers have operated. However, we have increased our operations in the Delaware sub-basin and are well-positioned to support further
33


increases to our activity in this area in response to demand from our customers. Over time, we expect the Permian Basin's Midland and Delaware sub-basins to continue to command a disproportionate share of future North American E&P spending.

Our hydraulic fracturing, wireline and cementing operations have been aggregated into one reportable segment: "Completion Services." In connection with our divestiture of our coiled tubing operations and the Silvertip Acquisition, we have revised our reportable segment presentation from Pressure Pumping to Completion Services and have restated prior periods accordingly. Our now discontinued coiled tubing, drilling and flowback operations were aggregated into the "All Other" category. For additional financial information on our reportable segments presentation, please see reportable segment information in Part II - Item 8, "Financial Statements and Supplementary Data."

Pioneer Pressure Pumping Acquisition
On December 31, 2018, we consummated the purchase of pressure pumping and related assets of Pioneer and Pioneer Pumping Services, LLC in the Pioneer Pressure Pumping Acquisition. In connection with the acquisition, we became a long-term service provider to Pioneer under the Pioneer Services Agreement, with a term of up to 10 years for providing pressure pumping and related services, with Pioneer having the right to terminate the agreement, in whole or part, effective as of December 31 of each of the calendar years of 2022, 2024 and 2026 and the right to increase the number of committed fleets prior to December 31, 2022. Under the agreement, the Company was entitled to receive compensation if Pioneer were to idle committed fleets ("idle fees"); however, we were first required to use all economically reasonable efforts to deploy the idled fleets to another customer. This agreement was superseded by the agreement below.
On March 31, 2022, we entered into an amended and restated A&R Pressure Pumping Services Agreement in place of the Pioneer Services Agreement. The A&R Pressure Pumping Services Agreement, which was effective from January 1, 2022 to December 31, 2022, reduced the number of contracted fleets from eight fleets to six fleets, modified the pressure pumping scope of work and pricing mechanism for contracted fleets, and replaced the idle fees arrangement with equipment reservation fees (the "Reservation fees"). As part of the Reservation fees arrangement, the Company was entitled to receive compensation for all eligible contracted fleets that were made available to Pioneer at the beginning of every quarter in 2022 through the term of the A&R Pressure Pumping Services Agreement. This agreement expired at the conclusion of its term and was replaced by the Fleet One Agreement and Fleet Two Agreement described below.
On October 31, 2022, we entered into the Fleet One Agreement and the Fleet Two Agreement with Pioneer, pursuant to which we will provide hydraulic fracturing services with two committed fleets, subject to certain termination and release rights. The Fleet One Agreement was effective as of January 1, 2023 and will terminate on August 31, 2023. The Fleet Two Agreement was effective as of January 1, 2023 and was originally planned to terminate on the one year anniversary of the date on which the fleet dedicated thereunder converted from a Tier II diesel Simul-Frac fleet to a Tier IV dual fuel zipper fleet, which was expected to occur in May 2023. In February 2023, Pioneer provided the Company notice (i) stating that Pioneer intended to release Fleet Two effective upon the completion of operations on the pad where the performance of Services (as defined in the Fleet Two Agreement) is in progress on May 12, 2023 and (ii) requesting that the Company agree to the termination of the Fleet Two Agreement as of the Release Date. The Company agreed with such request, and, as a result, the Fleet Two Agreement will be terminated as of the Release Date.
Commodity Price and Other Economic Conditions
The oil and gas industry has traditionally been volatile and is characterized by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves. The oil and gas industry is also impacted by general domestic and international economic conditions such as supply chain disruptions and inflation, political instability in oil producing countries, government regulations (both in the United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control.
The global public health crisis associated with the COVID-19 pandemic has had an adverse effect on global economic activity and the oil and gas industry in 2020 and 2021. Some of the challenges resulting from the COVID-19 pandemic that have impacted our business include restrictions on movement of personnel and associated gatherings, shortage of skilled labor, cost inflation and supply chain disruptions. In light of the COVID-19 pandemic, most companies, including our customers in the Permian Basin, reacted by closely managing their operating budget and exercising capital discipline in 2020 and 2021.
34


In February 2022, Russia launched a large-scale invasion of Ukraine that has led to significant armed hostilities. As a result, the United States, the United Kingdom, the member states of the European Union and other public and private actors have levied severe sanctions on Russian financial institutions, businesses and individuals. This conflict, and the resulting sanctions, has contributed to significant increases and volatility in the prices for oil and natural gas. The geopolitical and macroeconomic consequences of this invasion and associated sanctions remain uncertain, and such events, or any further hostilities in Ukraine or elsewhere, could severely impact the world economy and the oil and gas industry and may adversely affect our financial condition.
The Russia-Ukraine war, and the adverse impacts of the COVID-19 pandemic in recent years, including inflation, have resulted in volatility in supply and demand dynamics for crude oil and associated volatility in crude oil pricing. In 2022, WTI average crude oil price was approximately $94 per barrel, which is the highest average price in the last nine years. We believe that the recent surge in global crude oil prices is partly due to the lack of reinvestment in the oil and gas industry in the last two years, and increased demand for oil and gas products, coupled with the adverse impact of the Russia-Ukraine war, which has led to various sanctions on Russian crude oil supply and businesses. With the significant increase in global crude oil prices, including WTI crude oil prices, there has been an increase in the Permian Basin rig count from approximately 179 at the beginning of 2021 to approximately 353 at the end of December 2022, according to Baker Hughes. Following the increase in rig count and WTI crude oil price, the oilfield service industry has experienced increased demand for its completion services, and improved pricing. As a result of the growing demand for completion services and significant cost inflation across the industry, we negotiated pricing increases with certain of our customers for our completion services, depending on job design. Although we are currently operating in an improved pricing environment compared to 2020 and 2021, the rapid increase in cost inflation and supply chain tightness could adversely impact our future profitability. The U.S. inflation rate has been steadily increasing since 2021. These inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including labor costs and equipment. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to timely pass-through the cost increases to our customers, would negatively impact our business, financial condition and results of operations. See Part II, Item 1A. Risk Factors—"Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise."
Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including the upstream and oilfield services companies. As a result, we are working with our customers and equipment manufacturers to transition our equipment to a lower emissions profile. Currently, a number of lower emission solutions for pumping equipment, including Tier IV DGB, electric, direct drive gas turbine and other technologies have been developed, and we expect additional lower emission solutions will be developed in the future. We are continually evaluating these technologies and other investment and acquisition opportunities that would support our existing and new customer relationships. The transition to lower emissions equipment is quickly evolving and will be capital intensive. Over time, we may be required to convert substantially all of our conventional Tier II equipment to lower emissions equipment. We have transitioned our hydraulic fracturing equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022, and expect to increase to approximately 65% in 2023.
The Permian Basin rig count increase, demand for oil and gas products, WTI crude oil price increase and cost inflation could be indicative of an energy market recovery. If the rig count and market conditions continue to improve, including improved customers' pricing and labor availability, and we are able to continue to meet our customers' lower emissions equipment demands, we believe our operational and financial results will also continue to improve. However, if market conditions do not improve or decline in the future, and we are unable to increase our pricing or pass-through future cost increases to our customers, there could be a material adverse impact on our business, results of operations and cash flows.
Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to the holiday season, inclement winter weather and exhaustion of our customers' annual budgets. As a result, we typically experience declines in our operating and financial results in November and December, even in a stable commodity price and operations environment.
35


2022 Operational Highlights
Over the course of the year ended December 31, 2022:
improved pricing and increased operational efficiency at wellsites;
our average effectively utilized fleet count was approximately 15 active fleets, a 25% increase from approximately 12 active fleets in 2021;
we entered into a lease agreement for four electric fleets with 60,000 HHP per fleet, and we transitioned 162,500 HHP of our equipment portfolio to lower emissions, Tier IV DGB equipment. In 2023, our equipment portfolio is expected to be comprised of approximately 65% lower emissions (electric and Tier IV DGB), and 35% conventional diesel equipment;
we entered into a contract with a customer for the use of one of our electric hydraulic fracturing fleets to provide committed services for a period of three years after we take delivery of the fleet; and
on November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip Completion Services Operating, LLC, which provides wireline perforation and ancillary services solely in the Permian Basin.
2022 Financial Highlights
Financial highlights for the year ended December 31, 2022:
revenue increased $405.2 million, or 46.3%, to $1,279.7 million, as compared to $874.5 million for the year ended December 31, 2021;
cost of services (exclusive of depreciation and amortization) increased $220.6 million or 33.3% to $882.8 million, as compared to $662.3 million for the year ended December 31, 2021; cost of services as a percentage of revenue decreased to 69.0% in 2022 compared to 75.7% for the year ended December 31, 2021;
general and administrative expenses, inclusive of stock-based compensation, increased $28.8 million, or 34.8% to $111.8 million, as compared to $82.9 million for the year ended December 31, 2021;
the total impairment expense recorded during the year December 31, 2022 was approximately $57.5 million related to our DuraStim® equipment, compared to no impairment expense recorded during the year ended December 31, 2021;
net income was $2.0 million, compared to a net loss of $54.2 million for the year ended December 31, 2021. Diluted net income per common share was $0.02, compared to diluted net loss per common share of $0.53 for the year ended December 31, 2021. Adjusted EBITDA of approximately $316.6 million increased 134.5%, compared to $135.0 million for the year ended December 31, 2021 (see reconciliation of Adjusted EBITDA to net income (loss) in the subsequent section "How We Evaluate Our Operations") and margins increased 930 basis points;
our total liquidity was $155.2 million, consisting of cash, cash equivalents and restricted cash of $88.9 million and remaining availability of $66.3 million under our ABL Credit Facility; and
$30.0 million of borrowings as of December 31, 2022 under our ABL Credit Facility.
Our Assets and Operations
Through our Completion Services segment, which includes our hydraulic fracturing, cementing and wireline operations, we primarily provide hydraulic fracturing services to E&P companies in the Permian Basin. During the year ended December 31, 2022, our hydraulic fracturing, cementing and wireline operations accounted for 89.3%, 7.2% and 2.4% of our total revenue, respectively. Our equipment has been designed to handle Permian Basin specific operating conditions and the region’s increasingly high‑intensity well completions, which are characterized by longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant per well. We plan to continually reinvest in our equipment to ensure optimal performance and reliability.
36


In addition to our core Completion Services segment operations, we also offer a suite of complementary services, which we believe create operational efficiencies for our customers and could allow us to capture a greater portion of their capital spending across the lifecycle of a well in the future. In September 2022, we discontinued our coiled tubing operations and disposed of the coiled tubing assets.
How We Generate Revenue
We generate revenue primarily through our Completion Services segment, and more specifically, by providing hydraulic fracturing services to our customers. We own and operate a fleet of mobile hydraulic fracturing, wireline and cementing units and other auxiliary equipment to perform completion services to E&P companies. We also provide personnel and services that are tailored to meet each of our customers’ needs.
Hydraulic fracturing operations account for a significant portion of our total revenue. We charge our customers on a per‑job basis, in which we set pricing terms after receiving full specifications for the requested job, including the lateral length of the customer’s wellbore, the number of frac stages per well, the amount of proppant and chemicals to be used and other parameters of the job.
In addition to hydraulic fracturing services, we generate revenue through other completion services that we provide to our customers, including cementing, wireline and other related services. These completion services are provided through various contractual arrangements, including on a turnkey contract basis, in which we set a price to perform a particular job, or a daywork contract basis, in which we are paid a set price per day for our services. We are also sometimes paid by the hour for these complementary services.
Demand for our services is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count. Our revenue, profitability and cash flows are highly dependent upon prevailing crude oil prices and expectations about future prices. For many years, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. The average WTI oil prices per barrel were approximately $94, $68 and $39 for the years ended December 31, 2022, 2021 and 2020, respectively. In February 2023, the WTI oil price was approximately $78 per barrel. If the WTI oil price declines in the future or remains highly volatile, demand for our services may be negatively impacted, which could result in a significant decrease in our future profitability and cash flows. We monitor the oil and natural gas prices and the Permian Basin rig count to enable us to more effectively plan our business and forecast the demand for our services.
The historical weekly average Permian Basin rig count based on the Baker Hughes Company rig count information was as follows:
Year Ended December 31,
Drilling Rig Type (Permian Basin) 2022 2021 2020
Directional
Horizontal 318  227  212 
Vertical 14  11 
Total 335  240  221 
Average Permian Basin rig count to U.S rig count 46.3  % 50.5  % 51.0  %
Costs of Conducting our Business
The principal direct costs involved in operating our business are direct labor, expendables and other direct costs.
Direct Labor Costs. Payroll and benefit expenses related to our crews and other employees that are directly or indirectly attributable to the effective delivery of services are included in our operating costs. Direct labor costs amounted to 27.7% and 22.4% of total costs of service for the years ended December 31, 2022 and 2021, respectively. The increase in our direct labor costs percentage is driven by wage adjustments and higher headcount to support current activity levels.
Expendables. Expendables include the product and freight costs associated with proppant, chemicals and other consumables used in our completion services and other operations. These costs comprise a substantial variable component of our service costs, particularly with respect to the quantity and quality of sand and chemicals demanded when providing hydraulic fracturing services. Expendable product costs comprised approximately 33.6%, and 41.8% of total costs of service for the years ended December 31, 2022 and 2021, respectively. The percentage decrease in our expendables in 2022 was primarily attributable to certain customers electing to directly source sand and the associated logistics.
37


Other Direct Costs. We incur other direct expenses related to our service offerings, including the costs of fuel, repairs and maintenance, general supplies, equipment rental and other miscellaneous operating expenses. Fuel is consumed both in the operation and movement of our equipment. Repairs and maintenance costs are expenses directly related to upkeep of equipment, which have been amplified by the demand for higher horsepower jobs. Capital expenditures to upgrade or extend the useful life of equipment are capitalized and are not included in other direct costs. Other direct costs were 38.7% and 35.8% of total costs of service for the years ended December 31, 2022 and 2021, respectively. The percentage increase in 2022 was primarily driven by higher recurring repairs and maintenance costs in 2022 compared to 2021.
How We Evaluate Our Operations
Our management uses Adjusted EBITDA or Adjusted EBITDA margin to evaluate and analyze the performance of our various operating segments.
Adjusted EBITDA and Adjusted EBITDA Margin
We view Adjusted EBITDA and Adjusted EBITDA margin as important indicators of performance. We define EBITDA as our earnings, before (i) interest expense, (ii) income taxes and (iii) depreciation and amortization. We define Adjusted EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets, (ii) stock-based compensation, and (iii) other unusual or nonrecurring (income)/expenses, such as impairment charges, severance, costs related to asset acquisitions, insurance recoveries, costs related to nonrecurring legal settlement and one-time professional and advisory fees. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of our revenues.
Adjusted EBITDA and Adjusted EBITDA margin are supplemental measures utilized by our management and other users of our financial statements such as investors, commercial banks, and research analysts, to assess our financial performance because it allows us and other users to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization), nonrecurring (income) expenses and items outside the control of our management team (such as income taxes). Adjusted EBITDA and Adjusted EBITDA margin have limitations as analytical tools and should not be considered as an alternative to net income (loss), operating income (loss), cash flow from operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles in the United States of America ("GAAP").
Note Regarding Non‑GAAP Financial Measures
Adjusted EBITDA and Adjusted EBITDA margin are not financial measures presented in accordance with GAAP ("non-GAAP"), except when specifically required to be disclosed by GAAP in the financial statements. We believe that the presentation of Adjusted EBITDA and Adjusted EBITDA margin provide useful information to investors in assessing our financial condition and results of operations because it allows them to compare our operating performance on a consistent basis across periods and our peer group by removing the effects of our capital structure, asset base, nonrecurring (income) expenses and items outside the control of the Company. Net income (loss) is the GAAP measure most directly comparable to Adjusted EBITDA. Adjusted EBITDA and Adjusted EBITDA margin should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as analytical tools because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. You should not consider Adjusted EBITDA and Adjusted EBITDA margin in isolation or as a substitute for an analysis of our results as reported under GAAP. Because Adjusted EBITDA and Adjusted EBITDA margin may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
38



Reconciliation of net income (loss) to Adjusted EBITDA ($ in thousands):
Completion
Services
All Other
Total
Year ended December 31, 2022
Net income (loss) $ 19,754  $ (17,724) $ 2,030 
Depreciation and amortization
125,867  2,241  128,108 
Interest expense
1,605  —  1,605 
Income tax expense 5,356  —  5,356 
Loss on disposal of assets 88,145  14,005  102,150 
Impairment expense 57,454  —  57,454 
Stock‑based compensation
21,881  —  21,881 
Other income (2) (3)
(11,582) —  (11,582)
Other general and administrative expense (1)
8,460  —  8,460 
Severance expense 1,111  17  1,128 
Adjusted EBITDA
$ 318,051  $ (1,461) $ 316,590 
Completion
Services
All Other Total
Year ended December 31, 2021
Net loss $ (51,189) $ (2,996) $ (54,185)
Depreciation and amortization
129,780  3,597  133,377 
Interest expense
614  —  614 
Income tax benefit (14,252) —  (14,252)
Loss on disposal of assets 64,549  97  64,646 
Stock‑based compensation
11,519  —  11,519 
Other income (873) —  (873)
Other general and administrative expense (1)
(6,471) —  (6,471)
Severance expense 632  —  632 
Adjusted EBITDA
$ 134,309  $ 698  $ 135,007 
Completion
Services
All Other Total
Year ended December 31, 2020
Net loss $ (99,830) $ (7,190) $ (107,020)
Depreciation and amortization
148,936  4,354  153,290 
Interest expense
2,383  —  2,383 
Income tax benefit (27,480) —  (27,480)
Loss on disposal of assets
56,584  1,552  58,136 
Impairment expense 36,907  1,095  38,002 
Stock‑based compensation
9,100  —  9,100 
Other expense
874  —  874 
Other general and administrative expense (1)
13,038  —  13,038 
Retention bonus and severance expense 1,140  —  1,140 
Adjusted EBITDA
$ 141,652  $ (189) $ 141,463 
____________________
(1)During the years ended December 31, 2022, 2021 and 2020, other general and administrative expense (net of reimbursement from insurance carriers) primarily relates to nonrecurring professional fees paid to external consultants in connection with our audit committee review, SEC investigation, shareholder litigation, legal settlement to a vendor and other legal matters, net of insurance recoveries. During the years ended December 31, 2022, 2021
39


and 2020, we received reimbursement of approximately $10.4 million, $9.8 million and $0.6 million, respectively, from our insurance carriers in connection with the SEC investigation and shareholder litigation.
(2)Includes a $10.7 million net tax refund (net of advisory fees) received in March 2022 from the Texas Comptroller of Public Accounts in connection with limited sales, excise and use tax audit of the period from July 1, 2015 through December 31, 2018.
(3)Includes $2.7 million non-cash income from fixed asset inventory received as part of a settlement of warranty claims with an equipment manufacturer and a $1.6 million unrealized loss on short-term investment.
40


Results of Operations
In 2022, we conducted our business through four operating segments: hydraulic fracturing, cementing, wireline and coiled tubing. For reporting purposes, the hydraulic fracturing, cementing and wireline operating segments are aggregated into our one reportable segment—Completion Services. We disposed of our coiled tubing assets and shut down our coiled tubing operations effective September 1, 2022. The results of our coiled tubing operations prior to September 1, 2022 are reflected in the "All Other" category.
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021
($ in thousands, except percentages)
Year Ended December 31, Change
2022 2021 Variance %
Revenue $ 1,279,701  $ 874,514  $ 405,187  46.3  %
Less (Add):
Cost of services (1)
882,820  662,266  220,554  33.3  %
General and administrative expense (2)
111,760  82,921  28,839  34.8  %
Depreciation and amortization 128,108  133,377  (5,269) (4.0) %
Impairment expense 57,454  —  57,454  100.0  %
Loss on disposal of assets 102,150  64,646  37,504  58.0  %
Interest expense 1,605  614  991  161.4  %
Other expense (income) (11,582) (873) 10,709  1,226.7  %
Income tax expense (benefit) 5,356  (14,252) 19,608  137.6  %
Net income (loss) $ 2,030  $ (54,185) $ 56,215  103.7  %
Adjusted EBITDA (3)
$ 316,590  $ 135,007  $ 181,583  134.5  %
Adjusted EBITDA Margin (3)
24.7  % 15.4  % 9.3  % 60.4  %
   
Completion Services segment results of operations:
Revenue $ 1,266,261  $ 857,642  $ 408,619  47.6  %
Cost of services $ 869,053  $ 647,570  $ 221,483  34.2  %
Adjusted EBITDA $ 318,051  $ 134,309  $ 183,742  136.8  %
Adjusted EBITDA Margin (4)
25.1  % 15.7  % 9.4  % 59.9  %
____________________
(1)    Exclusive of depreciation and amortization.
(2)    Inclusive of stock‑based compensation.
(3)    For definitions of the non‑GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA margin and reconciliation of Adjusted EBITDA and Adjusted EBITDA margin to our most directly comparable financial measures calculated in accordance with GAAP, please read "How We Evaluate Our Operations." Included in our Adjusted EBITDA is reservation and idle fees of $27.0 million and $9.5 million for the years ended December 31, 2022 and 2021, respectively.
(4)    The non‑GAAP financial measure of Adjusted EBITDA margin for the Completion Services segment is calculated by taking Adjusted EBITDA for the Completion Services segment as a percentage of our revenues for the Completion Services segment.
41



Revenue.  Revenue increased 46.3%, or $405.2 million, to $1,279.7 million for the year ended December 31, 2022, as compared to $874.5 million for the year ended December 31, 2021. Our Completion Services segment revenues increased 47.6%, or $408.6 million for the year ended December 31, 2022, as compared to the year ended December 31, 2021. The increases were primarily attributable to the significant increase in our existing and new customers' activity levels, resulting in higher demand for completion services and improved pricing, and the additional revenue of $31.2 million following the Silvertip Acquisition. The increase in demand for our completion services resulted in an approximately 25% increase in our average effectively utilized fleet count to 15 active fleets in 2022 from 12 active fleets in 2021. Our revenue for the year ended December 31, 2022 included reservation fees charged to a customer of approximately $27.0 million and our revenue for the year ended December 31, 2021 included idle fees charged to a customer of approximately $9.5 million. The increase in these fees was driven by the A&R Pressure Pumping Services Agreement with Pioneer that required six dedicated fleets throughout 2022.
Revenues from services other than completion services decreased 20.3%, or approximately $3.4 million, for the year ended December 31, 2022, as compared to the year ended December 31, 2021. The decrease in revenues from services other than completion services during the year ended December 31, 2022, was primarily attributable to the discontinuation of our coiled tubing operations effective September 1, 2022.
Cost of Services.  Cost of services increased 33.3%, or $220.6 million, to $882.8 million for the year ended December 31, 2022, from $662.3 million during the year ended December 31, 2021. Cost of services in our Completion Services segment increased $221.5 million during the year ended December 31, 2022, as compared to the year ended December 31, 2021. The increases were primarily attributable to the significantly increased activity levels resulting from the increased demand for our services, the Silvertip Acquisition and the impact of general cost inflation. As a percentage of Completion Services segment revenues (including idle fees), Completion Services cost of services decreased to 68.6% for the year ended December 31, 2022, as compared to 75.5% for the year ended December 31, 2021. Excluding idle fees revenue of $27.0 million and $9.5 million for the years ended December 31, 2022 and 2021, respectively, our Completion Services cost of services as a percentage of Completion Services revenues for the years ended December 31, 2022 and 2021 was approximately 70.1% and 76.4%, respectively. The decrease in the percentages was a result of increased operational efficiencies, reduction in operational downtime and improved pricing across our customer base.
General and Administrative Expenses.  General and administrative expenses increased 34.8%, or $28.8 million, to $111.8 million for the year ended December 31, 2022, as compared to $82.9 million for the year ended December 31, 2021. The net increase was primarily attributable to (i) an increase in non-recurring legal expenses (net of insurance recoveries) by $11.1 million incurred primarily in connection with shareholder litigation and settlement with a vendor, (ii) an increase in stock-based compensation expense by $10.4 million, primarily attributable to the non-recurring incremental stock-based compensation associated with the acceleration of stock awards upon resignation of former executives, (iii) an increase in consulting and professional fees by $5.2 million, and (iv) the transaction costs related to the Silvertip Acquisition of approximately $2.2 million, partially offset by a net decrease of approximately $0.1 million in other general and administrative expenses.
Depreciation and Amortization.  Depreciation and amortization decreased 4.0%, or $5.3 million, to $128.1 million for the year ended December 31, 2022, as compared to $133.4 million for the year ended December 31, 2021. The decrease was primarily attributable to the decrease in our fixed asset base as of December 31, 2022, partly attributable to the disposal and impairment of certain fixed assets during the period.
Impairment Expense.  During the year ended December 31, 2022, we recorded $57.5 million in connection with the impairment of our DuraStim® assets, which is included in our Completion Services reportable segment. There was no impairment expense during the year ended December 31, 2021.
Loss on Disposal of Assets.  Loss on the disposal of assets increased 58.0%, or $37.5 million, to $102.1 million for the year ended December 31, 2022, as compared to $64.6 million for the year ended December 31, 2021. The increase was primarily attributable to the divestiture of our coiled tubing operations. We recorded a loss of $13.8 million in connection with the divestiture of our coiled tubing operations. In addition, upon replacement of certain property and equipment, including certain major components like fluid ends and power ends of our completion services equipment, the cost and related accumulated depreciation are removed from the balance sheet and the net amount is recognized as loss on disposal of assets.
Interest Expense.  Interest expense increased 161.4%, or $1.0 million, to $1.6 million for the year ended December 31, 2022, as compared to $0.6 million for the year ended December 31, 2021. The increase was primarily attributable to the partial write down of unamortized capitalized loan origination cost in connection with the modification to our credit facility and interest on borrowings under our ABL Credit Facility. We had $30.0 million in borrowings under our ABL Credit Facility at the end of 2022 compared to zero at the end of 2021.
42


Other (Income) Expense.  Other income increased to approximately $11.6 million for the year ended December 31, 2022, as compared to $0.9 million in income for the year ended December 31, 2021. The increase in other income is primarily attributable to the net tax refund to the Company of $10.7 million of sales, excise and use taxes, $2.7 million of non-cash income from equipment parts inventory received from an equipment manufacturer as settlement of our warranty claims, partially offset by a $1.6 million unrealized loss on short-term investment.
Income Taxes.  Income tax expense was $5.4 million for the year ended December 31, 2022, as compared to income tax benefit of $14.3 million for the year ended December 31, 2021. The reduction in income tax benefit recorded during the year ended December 31, 2022 is primarily attributable to the Company recording pre-tax income in 2022 as compared to pre-tax loss in 2021.
43


Liquidity and Capital Resources
Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our ABL Credit Facility. Our cash is primarily used to fund our operations, support growth opportunities and satisfy future debt payments. Our restricted cash, which was received from a customer will be used solely for the construction or operation of certain electric hydraulic fracturing equipment. Our Borrowing Base (as defined below), as redetermined monthly, is tied to 85.0% to 90.0% of eligible accounts receivable. Changes to our operational activity levels and our customers’ credit ratings have an impact on our total eligible accounts receivable, which could result in significant changes to our Borrowing Base and, therefore, our availability under our ABL Credit Facility.
As of December 31, 2022, our borrowings under our ABL Credit Facility were $30.0 million and our total liquidity was $155.2 million, consisting of cash, cash equivalents and restricted cash of $88.9 million and $66.3 million of availability under our ABL Credit Facility.
As of February 20, 2023, our borrowings under our ABL Credit Facility were $30.0 million and our total liquidity was approximately $142.8 million, consisting of cash and cash equivalents of $35.4 million and $107.4 million of availability under our ABL Credit Facility.
In 2020 when demand for our services was significantly depressed following the rapidly rising health crisis associated with the COVID-19 pandemic and the energy industry disruptions, the Company experienced a significant decrease in its liquidity. However, with the gradual recovery in the energy industry and the reduced impact of the COVID-19 pandemic, we have seen improvements in the demand for our services and improved pricing, and our liquidity position gradually improved. However, we expect our overall liquidity to decline if we make additional or accelerate our future capital investments. Moreover, the current market conditions may be impacted by increasing interest rates and potential economic slowdown or a new outbreak of a COVID-19 variant or other health crisis, which could negatively impact our future operations, revenue, profitability and cash flows.
There can be no assurance that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Future cash flows are subject to a number of variables, and are highly dependent on the drilling, completion, and production activity by our customers, which in turn is highly dependent on oil and natural gas prices. Depending upon market conditions and other factors, we may issue equity and debt securities or take other actions necessary to fund our business, strategy or meet our future long-term liquidity requirements.
Cash, Restricted Cash and Cash Flows
The following table sets forth our net cash provided by (used in) operating, investing and financing activities during the years ended December 31, 2022 and 2021, respectively.
Year Ended December 31,
($ in thousands)
2022 2021
Net cash provided by operating activities
$ 300,429  $ 154,714 
Net cash used in investing activities
$ (349,745) $ (104,292)
Net cash provided by (used in) financing activities
$ 26,260  $ (7,276)
Operating Activities
Net cash provided by operating activities was $300.4 million for the year ended December 31, 2022, as compared to $154.7 million for the year ended December 31, 2021. The net increase of $145.7 million was primarily due to the improvement in our net income, resulting from the significant increase in our existing and new customers' activity levels, resulting in higher demand for completion services and improved pricing. The net increase in cash provided by operating activities was also impacted by timing of our receivable collections from our customers and payment to our vendors.
Investing Activities
Net cash used in investing activities increased to $349.7 million for the year ended December 31, 2022, from $104.3 million for the year ended December 31, 2021. The net increase in our cash used in investing activities was primarily attributable to our investment in Tier IV DGB equipment (conversion of Tier II equipment to Tier IV DGB equipment and new Tier IV DGB equipment). The remaining cash payments in 2022 were incurred in connection with our maintenance capital expenditures, acquisition of our wireline business and other growth initiatives.
Financing Activities
Net cash provided by financing activities was $26.3 million for the year ended December 31, 2022, compared to net cash used of $7.3 million for the year ended December 31, 2021. The net increase in cash flow from financing activities during the year ended December 31, 2022 was primarily driven by borrowings of $30.0 million under our ABL Credit Facility during 2022 compared to no borrowings during the year ended December 31, 2021. During the year ended December 31, 2022, there was no cash inflow or outflow in connection with insurance financing, whereas during the year ended December 31, 2021 we had net cash outflow of approximately $5.5 million.
Credit Facility and Other Financing Arrangements
Our amended and revolving credit facility, as amended in 2018, had a total borrowing capacity of $300.0 million (subject to the borrowing base limit), with a maturity date of December 19, 2023. The revolving credit facility had a borrowing base of 85% of monthly eligible accounts receivable less customary reserves, as redetermined monthly. The revolving credit facility included a springing fixed charge coverage ratio to apply when excess availability was less than the greater of (i) 10% of the lesser of the facility size or the borrowing base or (ii) $22.5 million. Borrowings under the revolving credit facility accrued interest based on a three-tier pricing grid tied to availability, and we had the option to elect for loans to be based on either LIBOR or base rate, plus the applicable margin, which ranged from 1.75% to 2.25% for LIBOR loans and 0.75% to 1.25% for base rate loans, with a LIBOR floor of zero.
Effective April 13, 2022, the Company entered into an amendment and restatement of its revolving credit facility (as amended and restated, the "ABL Credit Facility"). The ABL Credit Facility decreased the borrowing capacity to $150.0 million (subject to the Borrowing Base (as defined below) limit), with the maturity date extended to April 13, 2027. The ABL Credit Facility has a borrowing base of 85% to 90%, depending on the credit ratings of our accounts receivable counterparties, of monthly eligible accounts receivable less customary reserves (the "Borrowing Base"), as redetermined monthly. The Borrowing Base as of December 31, 2022, was approximately $102.3 million. The ABL Credit Facility includes a springing fixed charge coverage ratio to apply when excess availability is less than the greater of (i) 10% of the lesser of the facility size or the Borrowing Base or (ii) $10.0 million. Under this facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company.
Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either the Secured Overnight Financing Rate ("SOFR") or the base rate, plus the applicable margin, which ranges from 1.50% to 2.00% for SOFR loans and 0.50% to 1.00% for base rate loans.
The loan origination costs relating to the ABL Credit Facility are classified as an asset in our balance sheet. As of December 31, 2022, we had borrowings of $30.0 million outstanding under our ABL Credit Facility.
Off Balance Sheet Arrangements
We had no material off balance sheet arrangements as of December 31, 2022.
Capital Requirements, Future Sources and Use of Cash
Capital expenditures incurred were $365.3 million during the year ended December 31, 2022, as compared to $165.2 million during the year ended December 31, 2021. During the year ended December 31, 2022, we increased our capital expenditures to support the increase in our existing and new customers’ activity levels and the transition of our hydraulic fracturing equipment
to lower emissions equipment. The significant portion of our total capital expenditures in 2022 comprised of maintenance capital expenditures and conversion of our hydraulic fracturing equipment to lower emissions equipment.
Our future material use of cash will be to fund our capital expenditures. Capital expenditures for 2023 are projected to be primarily related to capital expenditures to extend the useful life of our existing completion services assets, costs to convert some existing equipment to lower emissions equipment, strategic purchases and other ancillary equipment purchases, subject to market conditions and customer demand. Our future capital expenditures depend on our projected operational activity, emission requirements and planned conversions to lower emissions equipment, among other factors, which could vary significantly throughout the year. Based on our current plan and projected activity levels for 2023, we expect our capital expenditures to range between $250 million to $300 million. We could incur significant additional capital expenditures if our projected activity levels increase during the course of the year, inflation and supply chain tightness continues to adversely impact on our operations or we invest in new or different lower emissions equipment. The Company will continue to evaluate the emissions profile of its equipment over the coming years and may, depending on market conditions, convert or retire additional conventional Tier II equipment in favor of lower emissions equipment. The Company’s decisions regarding the retirement or conversion of equipment or the addition of lower emissions equipment will be subject to a number of factors, including (among other factors) the availability of equipment, including parts and major components, supply chain disruptions, prevailing and expected commodity prices, customer demand and requirements and the Company’s evaluation of projected returns on conversion or other capital expenditures. Depending on the impacts of these factors, the Company may decide to retain conventional equipment for a longer period of time or accelerate the retirement, replacement or conversion of that equipment.
    
We anticipate our capital expenditures will be funded by existing cash, cash flows from operations, and if needed, borrowings under our ABL Credit Facility. Our cash flows from operations will be generated from services we provide to our customers.
Contractual Obligations
The following table presents our contractual obligations and other commitments as of December 31, 2022:
($ in thousands)
 Period
Total  1 year or less More than 1 year
ABL Credit Facility (1)
$ 30,000  $ —  $ 30,000 
Operating leases (2)(3)
105,398  16,101  89,297 
Sand commitment (4)
31,680  31,680  — 
Equipment purchase commitments (5)
59,862  59,862  — 
Total $ 226,940  $ 107,643  $ 119,297 
____________________
(1)Exclusive of future commitment fees, amortization of deferred financing costs, interest expense or other fees on our ABL Credit Facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments of future interest rates to be changed. However, assuming a weighted average interest rate of 5.43%, and that our ABL Credit Facility debt balance remains the same, our estimated annual interest payment will be $1.6 million.
(2)Operating leases exclude short-term leases and other commitments (see Note 16. Leases and Note 17. Commitments and Contingencies in the financial statements for additional disclosures).
(3)Includes our leases for electric fracturing equipment (240,000 HHP), and power equipment to support electric equipment (70 MW). This equipment is expected to be delivered in 2023.
(4)Relates to a take-or-pay sand commitment with one of our sand vendors.
(5)Relates to commitments to purchase Tier IV DGB equipment.

We enter into other purchase agreements with Sand suppliers to secure supply of sand in the normal course of our business. The agreements with the Sand suppliers require that we purchase minimum volume of sand, based primarily on a certain percentage of our sand requirements from our customers or in certain situations based on predetermined fixed minimum volumes, otherwise certain penalties (shortfall fees) may be charged. The shortfall fee represents liquidated damages and is either a fixed percentage of the purchase price for the minimum volumes or a fixed price per ton of unpurchased volumes. Our current agreements with Sand suppliers expire at different times prior to December 31, 2025. Our agreed upon sand requirements or minimum volumes are based on certain future events such as our customer demand, which cannot be reasonably estimated. If the activity level of our customers declines and the future demand for our services is materially and adversely affected, we may be required to pay for more sand from one of our Sand suppliers than we need in the performance of our services, regardless of whether we take physical delivery of such sand. In such an event, we may be required to pay shortfall fees or other penalties under the purchase agreement, which could have a material adverse effect on our business, financial condition, or results of operations.
In January 2023, we entered into an equipment lease (the "Power Equipment Lease") for certain power generation equipment. The Power Equipment Lease has not yet commenced. We currently do not control the assets under the lease and have not taken possession of the assets. Therefore, the Company has not accounted for the right of use and lease obligation in its balance sheet as of December 31, 2022. The total estimated contractual commitment in connection with the Power Equipment Lease is approximately $59.6 million.
Recent Accounting Pronouncements
Disclosure concerning recently issued accounting standards is incorporated by reference to "Note 2- Significant Accounting Policies" of our Consolidated Financial Statements contained in this Annual Report.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally acceptable in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the years. We evaluate these estimates and assumptions on an ongoing basis and base our estimates on historical experience, current conditions and various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities as well as identifying and assessing the accounting treatment with respect to commitments and contingencies. Our actual results may materially differ from these estimates.
Listed below are the accounting policies that we believe are critical to our financial statements due to the degree of uncertainty regarding the estimates or assumptions involved, and that we believe are critical to the understanding of our operations.
Property and Equipment
Our property and equipment are recorded at cost, less accumulated depreciation.
Upon sale or retirement of property and equipment, the cost and related accumulated depreciation are removed from the balance sheet and the net amount, less proceeds from disposal, is recognized as a gain or loss in earnings.
We primarily retired certain components of equipment such as fluid ends and power ends, rather than the entire pieces of equipment, and the associated loss is recorded in our statement of operations as part of net loss on disposal of assets, which was $102.1 million, $64.6 million and $58.1 million for the years ended December 31, 2022, 2021 and 2020, respectively.
The estimated useful lives and salvage values of property and equipment is subject to key assumptions such as maintenance, utilization and job variation. Unanticipated future changes in these assumptions could negatively or positively impact our net income (loss). A 10% change in the useful lives of our property and equipment would have resulted in approximately $12.7 million impact on pre-tax loss during the year ended December 31, 2022. Depreciation of property and equipment is provided on the straight‑line method over estimated useful lives as shown in the table below.
Land
Indefinite
Buildings and property improvements
5 - 30 years
Vehicles
1 ‑ 5 years
Equipment
1 ‑ 22 years
Leasehold improvements
5 ‑ 20 years
44


Impairment of Long-Lived Assets
In accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 360 regarding Accounting for the Impairment or Disposal of Long‑Lived Assets, we review the long‑lived assets including intangible assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future undiscounted cash flows attributable to the assets is less than the carrying amount of such assets. In this circumstance, we recognize an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the asset. Our cash flow forecasts require us to make certain judgments regarding long‑term forecasts of future revenue and costs and cash flows related to the assets subject to review. The significant assumption in our cash flow forecasts is our estimated equipment utilization and profitability. The significant assumption is uncertain in that it is driven by future demand for our services and utilization, which could be impacted by crude oil market prices, future market conditions and technological advancements. Our fair value estimates for certain long‑lived assets require us to use significant other observable inputs, including assumptions related to market based on recent auction sales or selling prices of comparable equipment. The estimates of fair value are also subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future.
If the crude oil market declines or the demand for our services does not recover, and if our equipment remains idle or under‑utilized, the estimated fair value of such equipment may decline, which could result in future impairment charges. Though the impacts of variations in any of these factors can have compounding or off‑setting impacts, a 10% decline in the estimated future cash flows of our existing asset groups will not indicate an impairment.
In 2022, we recorded impairment expense of $57.5 million on our DuraStim® equipment because it remained idled and there were no near term plans to deploy the DuraStim® equipment to the customers’ wellsite.
Goodwill and Other Intangible Assets
Goodwill is the excess of the consideration transferred over the fair value of the tangible and identifiable intangible assets and liabilities recognized. Goodwill is not amortized. We perform an annual impairment test of goodwill and intangible assets as of December 31, or more frequently if circumstances indicate that impairment may exist.
In connection with the Silvertip Acquisition, we added $23.6 million of goodwill during the year ended December 31, 2022. There was no write-off of goodwill during the year ended December 31, 2022. We performed our annual goodwill impairment test in accordance with ASC 350, Intangibles—Goodwill and Other, on December 31, 2022, at which time, we determined that the fair value of our wireline reporting unit was substantially in excess of its carrying value. The wireline operating segment is the only segment which has goodwill at December 31, 2022. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted equipment utilization, pricing and cost assumptions. Our discounted cash flow analysis includes significant assumptions regarding discount rates, utilization, expected profitability margin, forecasted maintenance capital expenditures, and the timing of expected cash flow. As such, our goodwill analysis incorporates inherent uncertainties that are difficult to predict in volatile economic environments and could result in impairment charges in future periods if actual results materially differ from the estimated assumptions utilized in our forecast. The carrying value of goodwill in our balance sheet as of December 31, 2022 was $23.6 million.
Intangible assets consist of customer relationships and trademark/trade name. In connection with the Silvertip Acquisition, we added intangible assets consisting of $46.5 million of customer relationships and $10.8 million of trademark/trade name. Intangible assets are amortized on a straight‑line basis with an estimated useful life of ten years. Our estimated useful life could be sensitive to changes in market conditions and management’s judgment, and are likely to change in the future if certain events occur. Presently, there are no events or circumstances that will cause us to believe that our estimated useful life for our intangible assets are likely to change.
Income Taxes
Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of differences between the consolidated financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
45


We recognize deferred tax assets to the extent that we believe these assets are more likely than not to be realized. In making such a determination, we consider all positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, and the results of recent operations. If we determine that we would not be able to fully realize our deferred tax assets in the future in excess of their net recorded amount, we would record a valuation allowance, which would increase our provision for income taxes. In determining our need for a valuation allowance as of December 31, 2022, we have considered and made judgments and estimates regarding estimated future taxable income. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to record additional valuation allowances for our deferred tax assets and the ultimate realization of tax assets depends on the generation of sufficient taxable income.
Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates. Additionally, we forecast certain tax elements, such as future taxable income, as well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts. The final determination of our income tax liabilities involves the interpretation of local tax laws and related authorities in each jurisdiction. Changes in the operating environments, including changes in tax law, could impact the determination of our income tax liabilities for a tax year.
46


Item 7A. Quantitative and Qualitative Disclosure of Market Risks
Foreign Currency Exchange Risk
Our operations are currently conducted entirely within the U.S; therefore, we had no significant exposure to foreign currency exchange risk in 2022.
Commodity Price Risk
Our materials and fuel purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our completion services such as proppants, perforating guns, chemicals, guar, trucking and fluid supplies. Our fuel costs consist primarily of diesel and natural gas used by our various trucks and other motorized equipment. The prices for fuel and materials in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Historically, we have generally been able to pass along a significant portion of our commodity price risk to our customers; however, we may be unable to do so in the future. We do not engage in commodity price hedging activities.
Interest Rate Risk
We may be subject to interest rate risk on variable rate borrowings under our ABL Credit Facility. We do not currently engage in interest rate derivatives to hedge our interest rate risk. The impact of a 1% increase in interest rates on our variable rate debt would have resulted in an increase in interest expense and corresponding decrease/(increase) in pre‑tax income/(loss) of approximately $0.1 million, $0 and $0.4 million, for the years ended December 31, 2022, 2021 and 2020, respectively.
Credit Risk
Financial instruments that potentially subject us to concentrations of credit risk are trade receivables. We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including maintaining an allowance for doubtful accounts.
47


Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
ProPetro Holding Corp. and Subsidiaries

Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of ProPetro Holding Corp. and Subsidiaries (the "Company") as of December 31, 2022 and 2021, the related consolidated statements of operations, shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2022, and the related notes (collectively, referred to as, the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.
 We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2023, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impairment of Long-Lived Assets — Refer to Note 2 and 5 to the consolidated financial statements
Critical Audit Matter Description
The Company reviews the carrying value of long-lived assets such as property and equipment and other assets, whenever events or circumstances indicate that the carrying value of long-lived assets may not be recoverable. The Company’s evaluation of the recoverability of assets involves the comparison of undiscounted future cash flows attributable to the asset over the Company’s estimated carrying amount of such asset. As a result of a triggering event for the quarter ended June 30, 2022, management deemed it necessary to assess the recoverability of its DuraStim® hydraulic fracturing equipment. The Company determined that the DuraStim® hydraulic fracturing equipment was impaired and an impairment expense of approximately $57.5 million was recorded for the three months ended June 30, 2022. The estimated fair value of the DuraStim® hydraulic fracturing equipment was determined using the cost approach and significant unobservable inputs, including cost Index curve selection,
48


trend factor calculation, replacement cost, normal useful life, functional obsolescence selections, and minimum percent good, among others.
We identified the impairment of DuraStim® hydraulic fracturing equipment as a critical audit matter because of the significant estimates and assumptions management makes to evaluate the recoverability of these assets. This required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists, when performing audit procedures to evaluate the reasonableness of management’s assumptions related to cost index curve selection, trend factor calculation, replacement cost, normal useful life, functional obsolescence selection, and minimum percent good.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the fair value of DuraStim® hydraulic fracturing equipment included the following, among others:
We tested the operating effectiveness of controls over management’s evaluation of the recoverability of long-lived assets.
With the assistance of our fair value specialists:
We evaluated the reasonableness of the valuation analysis, including estimates of cost index curve selection, trend factor calculation, replacement cost, normal useful life, functional obsolescence selections, and minimum percent good by (1) evaluating the source information and assumptions used by management, (2) testing the mathematical accuracy of the valuation analysis, and (3) developing independent estimates and comparing our estimates to those used by management.

We considered any events occurring after the impairment date that may indicate a different valuation for the assets impaired.
We considered events and circumstances and performed procedures to ensure the accuracy of the triggering event date.
Acquisition — Silvertip Completion Services Operating, LLC — Fair value of assets acquired and liabilities assumed - Refer to Notes 1, 2, and 4 to the financial statements
Critical Audit Matter Description
The Company completed the acquisition of Silvertip Completion Operating Services, LLC ("Silvertip") for a total purchase consideration of $148.1 million on November 1, 2022 (the "Acquisition"). The Company accounted for the Acquisition using the acquisition method of accounting for business combinations. Accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on their respective estimated fair values. The largest asset classes acquired include property and equipment consisting mainly of pumpdown pumps, pumpdown wireline trucks, vehicles, pressure control and wireline equipment, and intangible assets consisting of customer relationships and trademark/trade name. The method for determining fair value varied depending on the type of the asset or liability and involved management making significant estimates related to assumptions such as future cash flows, discount rate, attrition rate, royalty rate, cost index curve selection, trend factor calculation, replacement cost, normal useful life, and minimum percent good.
We identified the valuation of property and equipment and intangible assets arising out of the Acquisition as a critical audit matter because of the estimates and assumptions management makes to determine the fair value of these assets. This required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists, when performing audit procedures to evaluate the reasonableness of management’s assumptions related to future cash flows, discount rate, attrition rate, royalty rate, cost index curve selection, trend factor calculation, replacement cost, normal useful life, and minimum percent good.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the fair value of property and equipment and intangible assets acquired as part of the Acquisition included the following, among others:
We tested the effectiveness of controls over business combinations.
With the assistance of our fair value specialists:
49


For property and equipment, we evaluated the reasonableness of the valuation methodology and significant assumptions including estimates of cost index curve selection, trend factor calculation, replacement cost, normal useful life, and minimum percent good by (1) evaluating the source information and assumptions used by management, (2) testing the mathematical accuracy of the calculation, and (3) comparing our estimates to those used by management.
For intangible assets, we evaluated the reasonableness of the valuation methodology and significant assumptions including discount rate, attrition rate, and royalty rate by (1) evaluating the source information and assumptions used by management, (2) testing the mathematical accuracy of the calculation, and (3) comparing our estimates to those used by management.
For intangible assets, we evaluated whether the estimated future cash flows used in the income approach were consistent with projections used by the Company, as well as evidence obtained in other areas of the audit
We considered any events or transactions occurring after the Acquisition date that may indicate a different valuation for the assets acquired and liabilities assumed.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 23, 2023
We have served as the Company's auditor since 2013.


50


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
ProPetro Holding Corp. and Subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of ProPetro Holding Corp. and Subsidiaries (the "Company") as of December 31, 2022, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control—Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2022, of the Company and our report dated February 23, 2023, expressed an unqualified opinion on those consolidated financial statements.
As described in Management’s Report on Internal Control Over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Silvertip Completion Services Operating, LLC, which was acquired on November 1, 2022 and whose financial statements constitute 13.0% and 2.4% of total assets and revenue, respectively of the consolidated financial statement amounts as of and for the year ended December 31, 2022. Accordingly, our audit did not include the internal control over financial reporting at Silvertip Completion Services Operating, LLC.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 23, 2023
51



PROPETRO HOLDING CORP.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2022 AND 2021
(In thousands, except share data)
2022 2021
ASSETS
CURRENT ASSETS:
Cash, cash equivalents and restricted cash $ 88,862  $ 111,918 
Accounts receivable - net of allowance for credit losses of $419 and $217, respectively
215,925  128,148 
Inventories
5,034  3,949 
Prepaid expenses
8,643  6,752 
Short-term investment, net 10,283   
Other current assets
38  297 
Total current assets
328,785  251,064 
PROPERTY AND EQUIPMENT - Net of accumulated depreciation
922,735  808,494 
OPERATING LEASE RIGHT-OF-USE ASSETS
3,147  409 
OTHER NONCURRENT ASSETS:
Goodwill 23,624   
Intangible assets - net of amortization 56,345   
Other noncurrent assets
1,150  1,269 
Total other noncurrent assets
81,119  1,269 
TOTAL ASSETS
$ 1,335,786  $ 1,061,236 
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable
$ 234,299  $ 152,649 
Accrued and other current liabilities
49,027  20,767 
Operating lease liabilities
854  369 
Total current liabilities
284,180  173,785 
DEFERRED INCOME TAXES
65,265  61,052 
LONG-TERM DEBT
30,000   
NONCURRENT OPERATING LEASE LIABILITIES
2,308  97 
Total liabilities
381,753  234,934 
COMMITMENTS AND CONTINGENCIES (Note 17)
SHAREHOLDERS’ EQUITY:
Preferred stock, $0.001 par value, 30,000,000 shares authorized, none issued, respectively
   
Common stock, $0.001 par value, 200,000,000 shares authorized, 114,515,008 and 103,437,177 shares issued, respectively
114  103 
Additional paid-in capital
970,519  844,829 
Accumulated deficit
(16,600) (18,630)
Total shareholders’ equity
954,033  826,302 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$ 1,335,786  $ 1,061,236 
See notes to consolidated financial statements. 52


PROPETRO HOLDING CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2022
, 2021 AND 2020
(In thousands, except per share data)
2022 2021 2020
REVENUE - Service revenue
$ 1,279,701  $ 874,514  $ 789,232 
COSTS AND EXPENSES:
Cost of services (exclusive of depreciation and amortization)
882,820  662,266  584,279 
General and administrative (inclusive of stock‑based compensation) 111,760  82,921  86,768 
Depreciation and amortization
128,108  133,377  153,290 
Impairment expense
57,454    38,002 
Loss on disposal of assets
102,150  64,646  58,136 
Total costs and expenses
1,282,292  943,210  920,475 
OPERATING INCOME (LOSS)
(2,591) (68,696) (131,243)
OTHER INCOME (EXPENSE):
Interest expense
(1,605) (614) (2,383)
Other income (expense)
11,582  873  (874)
Total other income (expense)
9,977  259  (3,257)
INCOME (LOSS) BEFORE INCOME TAXES 7,386  (68,437) (134,500)
INCOME TAX (EXPENSE) BENEFIT
(5,356) 14,252  27,480 
NET INCOME (LOSS)
$ 2,030  $ (54,185) $ (107,020)
NET INCOME (LOSS) PER COMMON SHARE:
Basic
$ 0.02  $ (0.53) $ (1.06)
Diluted
$ 0.02  $ (0.53) $ (1.06)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic
105,868  102,655  100,829 
Diluted
106,939  102,655  100,829 


See notes to consolidated financial statements. 53


PROPETRO HOLDING CORP.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2022
, 2021 AND 2020
(In thousands)
Common Stock
Shares Amount Additional
Paid‑In
Capital
Retained Earnings (Accumulated
Deficit)
Total
BALANCE - January 1, 2020 100,624  $ 101  $ 826,629  $ 142,575  $ 969,305 
Stock‑based compensation cost —  —  9,100  —  9,100 
Issuance of equity award—net 289  —  —  —  — 
Tax withholdings paid for net settlement of equity awards —  —  (614) —  (614)
Net loss —  —  —  (107,020) (107,020)
BALANCE - December 31, 2020 100,913  $ 101  $ 835,115  $ 35,555  $ 870,771 
Stock‑based compensation cost —  —  11,519  —  11,519 
Issuance of equity awards—net 2,524  2  4,015  —  4,017 
Tax withholdings paid for net settlement of equity awards —  —  (5,820) —  (5,820)
Net loss —  —  —  (54,185) (54,185)
BALANCE - December 31, 2021 103,437  $ 103  $ 844,829  $ (18,630) $ 826,302 
Stock‑based compensation cost —  —  21,881  —  21,881 
Issuance of equity—net 11,078  11  107,688  —  107,699 
Tax withholdings paid for net settlement of equity awards —  —  (3,879) —  (3,879)
Net income —  —  —  2,030  2,030 
BALANCE - December 31, 2022 114,515  $ 114  $ 970,519  $ (16,600) $ 954,033 

See notes to consolidated financial statements. 54


PROPETRO HOLDING CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2022
, 2021 AND 2020
(In thousands)
2022 2021 2020
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 2,030