[10-Q] Patterson-UTI Energy Inc Quarterly Earnings Report

Rhea-AI Filing Summary

Patterson-UTI Energy (PTEN) posted a sharp swing to loss in Q2 25. Revenue fell 10% YoY to $1.22 bn, driven by softer activity in Drilling (-8%) and Completion Services (-11%). Operating results turned from a $45 m profit to a $29 m loss as lower volumes, cost pressure and a $27.8 m impairment on Latin-American drilling assets weighed on margins. Net loss attributable to shareholders was $49.1 m (-$0.13/sh) versus $11.1 m (+$0.03) a year ago.

For 1H 25, revenue declined 13% to $2.50 bn and the company recorded a $47.4 m net loss. Cash flow from operations dropped to $347.9 m (-38%), while capex remained high at $306 m, cutting cash on hand to $185.9 m (31 Dec 24: $241.3 m). Liquidity is supported by an undrawn $500 m unsecured revolver (available $498 m) and no near-term debt maturities after retiring $6.4 m of equipment loans.

Balance-sheet equity slipped 4% to $3.35 bn, largely from losses and $35.8 m of share repurchases (4.28 m shares). PTEN maintained its quarterly dividend at $0.08/sh (payout $30.7 m) and still has $728 m remaining on its $1 bn buyback authorisation.

Segment view: Drilling Services stayed profitable ($40.6 m) but Completion Services swung to a $29.2 m loss; Drilling Products earned $6.8 m. Contract drilling backlog stands at $312 m, with 9% extending beyond 12 months.

Outlook concerns: lower U.S. rig counts, OPEC+ supply increases and macro uncertainty pressured activity; management warns further weakness could trigger additional impairments.

Positive

• Strong liquidity: $185.9 m cash plus $498 m undrawn revolver provides ample headroom.
• No near-term maturities: only long-dated unsecured notes remain after retiring equipment loans.
• Ongoing shareholder returns: dividend maintained at $0.08 and $35.8 m stock repurchased; $728 m authorisation left.

Negative

• Revenue down 10% YoY and company swung to a $29 m operating loss.
• Net loss $49 m; EPS -$0.13 vs +$0.03 prior year.
• Cash from operations −38%, driving $55 m decline in cash balance.
• $27.8 m impairment on Latin American drilling assets reflects deteriorating outlook.
• Completion Services segment loss of $29 m highlights margin pressure.

Insights

Sell-side Energy Analyst

TL;DR: PTEN’s Q2 shows demand softness and margin squeeze; liquidity intact but earnings momentum negative.

Revenue contraction and the return to operating losses confirm North American land weakness, especially in pressure pumping. The 2.4 pp sequential drop in EBIT margin (now -2.4%) plus the $27.8 m impairment underscore oversupply and pricing pressure. Cash burn before financing (-$54 m) is manageable thanks to the new $500 m revolver and a comfortable 41% debt-to-cap ratio, but FCF is unlikely until volumes recover. Guidance was not provided, yet backlog of $312 m (down 18% QoQ) signals limited near-term rebound. Dividend looks safe short term, but further buybacks could slow if cash flow stays weak.

Oilfield Services Specialist

TL;DR: Segment mix deteriorated; Completion Services now loss-making—strategic review may be needed.

Drilling Services remains PTEN’s earnings anchor, generating $40.6 m despite lower dayrates. However, Completion Services posted a $29 m loss as frac spreads idle and consumable costs stay sticky—raising questions on fleet rationalisation. Drilling Products margin held up (7.7% op margin), validating last year’s Ulterra acquisition, though goodwill headroom is thin (fair value only 8% above carrying amount). Management’s decision to maintain shareholder returns amid negative earnings suggests confidence in cyclical recovery, yet investors should watch 2026 frac calendar and potential asset sales.

0000889900--12-31false2025Q2P2D12910.5xbrli:sharesiso4217:USDiso4217:USDxbrli:sharesxbrli:purepten:reportingUnitpten:tradingDaypten:segment00008899002025-01-012025-06-3000008899002025-07-2300008899002025-06-3000008899002024-12-310000889900pten:DrillingServicesMember2025-04-012025-06-300000889900pten:DrillingServicesMember2024-04-012024-06-300000889900pten:DrillingServicesMember2025-01-012025-06-300000889900pten:DrillingServicesMember2024-01-012024-06-300000889900pten:CompletionServicesMember2025-04-012025-06-300000889900pten:CompletionServicesMember2024-04-012024-06-300000889900pten:CompletionServicesMember2025-01-012025-06-300000889900pten:CompletionServicesMember2024-01-012024-06-300000889900pten:DrillingProductsMember2025-04-012025-06-300000889900pten:DrillingProductsMember2024-04-012024-06-300000889900pten:DrillingProductsMember2025-01-012025-06-300000889900pten:DrillingProductsMember2024-01-012024-06-300000889900pten:OtherMember2025-04-012025-06-300000889900pten:OtherMember2024-04-012024-06-300000889900pten:OtherMember2025-01-012025-06-300000889900pten:OtherMember2024-01-012024-06-3000008899002025-04-012025-06-3000008899002024-04-012024-06-3000008899002024-01-012024-06-300000889900us-gaap:CommonStockMember2024-12-310000889900us-gaap:AdditionalPaidInCapitalMember2024-12-310000889900us-gaap:RetainedEarningsMember2024-12-310000889900us-gaap:AccumulatedOtherComprehensiveIncomeMember2024-12-310000889900us-gaap:TreasuryStockCommonMember2024-12-310000889900us-gaap:NoncontrollingInterestMember2024-12-310000889900us-gaap:RetainedEarningsMember2025-01-012025-03-310000889900us-gaap:NoncontrollingInterestMember2025-01-012025-03-3100008899002025-01-012025-03-310000889900us-gaap:AccumulatedOtherComprehensiveIncomeMember2025-01-012025-03-310000889900us-gaap:CommonStockMember2025-01-012025-03-310000889900us-gaap:AdditionalPaidInCapitalMember2025-01-012025-03-310000889900us-gaap:TreasuryStockCommonMember2025-01-012025-03-310000889900us-gaap:CommonStockMember2025-03-310000889900us-gaap:AdditionalPaidInCapitalMember2025-03-310000889900us-gaap:RetainedEarningsMember2025-03-310000889900us-gaap:AccumulatedOtherComprehensiveIncomeMember2025-03-310000889900us-gaap:TreasuryStockCommonMember2025-03-310000889900us-gaap:NoncontrollingInterestMember2025-03-3100008899002025-03-310000889900us-gaap:RetainedEarningsMember2025-04-012025-06-300000889900us-gaap:NoncontrollingInterestMember2025-04-012025-06-300000889900us-gaap:AccumulatedOtherComprehensiveIncomeMember2025-04-012025-06-300000889900us-gaap:CommonStockMember2025-04-012025-06-300000889900us-gaap:AdditionalPaidInCapitalMember2025-04-012025-06-300000889900us-gaap:TreasuryStockCommonMember2025-04-012025-06-300000889900us-gaap:CommonStockMember2025-06-300000889900us-gaap:AdditionalPaidInCapitalMember2025-06-300000889900us-gaap:RetainedEarningsMember2025-06-300000889900us-gaap:AccumulatedOtherComprehensiveIncomeMember2025-06-300000889900us-gaap:TreasuryStockCommonMember2025-06-300000889900us-gaap:NoncontrollingInterestMember2025-06-300000889900us-gaap:CommonStockMember2023-12-310000889900us-gaap:AdditionalPaidInCapitalMember2023-12-310000889900us-gaap:RetainedEarningsMember2023-12-310000889900us-gaap:AccumulatedOtherComprehensiveIncomeMember2023-12-310000889900us-gaap:TreasuryStockCommonMember2023-12-310000889900us-gaap:NoncontrollingInterestMember2023-12-3100008899002023-12-310000889900us-gaap:RetainedEarningsMember2024-01-012024-03-310000889900us-gaap:NoncontrollingInterestMember2024-01-012024-03-3100008899002024-01-012024-03-310000889900us-gaap:AccumulatedOtherComprehensiveIncomeMember2024-01-012024-03-310000889900us-gaap:TreasuryStockCommonMember2024-01-012024-03-310000889900us-gaap:CommonStockMember2024-01-012024-03-310000889900us-gaap:AdditionalPaidInCapitalMember2024-01-012024-03-310000889900us-gaap:CommonStockMember2024-03-310000889900us-gaap:AdditionalPaidInCapitalMember2024-03-310000889900us-gaap:RetainedEarningsMember2024-03-310000889900us-gaap:AccumulatedOtherComprehensiveIncomeMember2024-03-310000889900us-gaap:TreasuryStockCommonMember2024-03-310000889900us-gaap:NoncontrollingInterestMember2024-03-3100008899002024-03-310000889900us-gaap:RetainedEarningsMember2024-04-012024-06-300000889900us-gaap:NoncontrollingInterestMember2024-04-012024-06-300000889900us-gaap:AccumulatedOtherComprehensiveIncomeMember2024-04-012024-06-300000889900us-gaap:CommonStockMember2024-04-012024-06-300000889900us-gaap:AdditionalPaidInCapitalMember2024-04-012024-06-300000889900us-gaap:TreasuryStockCommonMember2024-04-012024-06-300000889900us-gaap:CommonStockMember2024-06-300000889900us-gaap:AdditionalPaidInCapitalMember2024-06-300000889900us-gaap:RetainedEarningsMember2024-06-300000889900us-gaap:AccumulatedOtherComprehensiveIncomeMember2024-06-300000889900us-gaap:TreasuryStockCommonMember2024-06-300000889900us-gaap:NoncontrollingInterestMember2024-06-3000008899002024-06-300000889900srt:MinimumMember2025-06-300000889900srt:MaximumMember2025-06-300000889900srt:MinimumMember2025-01-012025-06-300000889900srt:MaximumMember2025-01-012025-06-3000008899002026-07-012025-06-3000008899002025-07-012025-06-300000889900us-gaap:EquipmentMember2025-06-300000889900us-gaap:EquipmentMember2024-12-310000889900us-gaap:OilAndGasPropertiesMember2025-06-300000889900us-gaap:OilAndGasPropertiesMember2024-12-310000889900us-gaap:BuildingMember2025-06-300000889900us-gaap:BuildingMember2024-12-310000889900pten:RentalEquipmentMember2025-06-300000889900pten:RentalEquipmentMember2024-12-310000889900us-gaap:LandMember2025-06-300000889900us-gaap:LandMember2024-12-310000889900us-gaap:PropertyPlantAndEquipmentMember2025-04-012025-06-300000889900us-gaap:PropertyPlantAndEquipmentMember2024-04-012024-06-300000889900us-gaap:PropertyPlantAndEquipmentMember2025-01-012025-06-300000889900us-gaap:PropertyPlantAndEquipmentMember2024-01-012024-06-300000889900pten:CementingServicesMember2025-04-012025-06-300000889900pten:DrillingProductsMemberMember2025-06-300000889900pten:DrillingProductsMemberMember2025-01-012025-06-300000889900us-gaap:CustomerRelationshipsMember2025-06-300000889900us-gaap:CustomerRelationshipsMember2024-12-310000889900us-gaap:DevelopedTechnologyRightsMember2025-06-300000889900us-gaap:DevelopedTechnologyRightsMember2024-12-310000889900us-gaap:TradeNamesMember2025-06-300000889900us-gaap:TradeNamesMember2024-12-310000889900us-gaap:OtherIntangibleAssetsMember2025-06-300000889900us-gaap:OtherIntangibleAssetsMember2024-12-310000889900pten:ThreePointNineFivePercentSeniorNotesDue2028Member2025-06-300000889900pten:ThreePointNineFivePercentSeniorNotesDue2028Member2024-12-310000889900pten:FivePointOneFivePercentSeniorNotesDue2029Member2025-06-300000889900pten:FivePointOneFivePercentSeniorNotesDue2029Member2024-12-310000889900pten:SevenPointOneFivePercentSeniorNotesDueSeptember2033Member2025-06-300000889900pten:SevenPointOneFivePercentSeniorNotesDueSeptember2033Member2024-12-310000889900pten:EquipmentLoansDueTwoThousandTwentyFiveMember2025-06-300000889900pten:EquipmentLoansDueTwoThousandTwentyFiveMember2024-12-310000889900pten:CreditAgreementMember2025-01-310000889900us-gaap:RevolvingCreditFacilityMemberpten:CreditAgreementMember2025-01-310000889900us-gaap:RevolvingCreditFacilityMemberpten:CreditAgreementMemberus-gaap:LetterOfCreditMember2025-01-310000889900us-gaap:BridgeLoanMemberpten:CreditAgreementMember2025-01-310000889900pten:CreditAgreementMemberus-gaap:SecuredOvernightFinancingRateSofrMember2025-01-312025-01-310000889900pten:CreditAgreementMemberpten:FloorRateMember2025-01-312025-01-310000889900us-gaap:SecuredOvernightFinancingRateSofrMemberpten:CreditAgreementMembersrt:MinimumMember2025-01-312025-01-310000889900us-gaap:SecuredOvernightFinancingRateSofrMemberpten:CreditAgreementMembersrt:MaximumMember2025-01-312025-01-310000889900us-gaap:BaseRateMemberpten:CreditAgreementMembersrt:MinimumMember2025-01-312025-01-310000889900us-gaap:BaseRateMemberpten:CreditAgreementMembersrt:MaximumMember2025-01-312025-01-310000889900pten:CreditAgreementMemberus-gaap:SecuredOvernightFinancingRateSofrMember2025-01-012025-06-300000889900pten:CreditAgreementMemberus-gaap:BaseRateMember2025-01-012025-06-300000889900pten:CreditAgreementMembersrt:MinimumMember2025-01-312025-01-310000889900pten:CreditAgreementMembersrt:MaximumMember2025-01-312025-01-310000889900pten:CreditAgreementMember2025-01-312025-01-310000889900pten:CreditAgreementMember2025-01-012025-06-300000889900us-gaap:RevolvingCreditFacilityMember2025-06-300000889900us-gaap:RevolvingCreditFacilityMemberpten:CreditAgreementMember2025-06-300000889900pten:ReimbursementAgreementMember2025-06-300000889900pten:ReimbursementAgreementMemberpten:LondonInterBankOfferedRateMember2015-03-162015-03-160000889900pten:ReimbursementAgreementMember2015-03-162015-03-160000889900pten:ThreePointNineFivePercentSeniorNotesDueJanuaryTwoThousandTwentyEightMember2018-01-190000889900pten:FivePointOneFivePercentSeniorNotesDueNovemberTwoThousandTwentyNineMember2019-11-150000889900pten:SevenPointOneFivePercentSeniorNotesDueSeptember2023Member2023-09-130000889900pten:ThreePointNineFivePercentSeniorNotesDueJanuaryTwoThousandTwentyEightMember2025-01-012025-06-300000889900pten:ThreePointNineFivePercentSeniorNotesDueJanuaryTwoThousandTwentyEightMember2018-01-192018-01-190000889900pten:FivePointOneFivePercentSeniorNotesDueNovemberTwoThousandTwentyNineMember2025-01-012025-06-300000889900pten:FivePointOneFivePercentSeniorNotesDueNovemberTwoThousandTwentyNineMember2019-11-152019-11-150000889900pten:SevenPointOneFivePercentSeniorNotesDueSeptember2023Member2025-01-012025-06-300000889900pten:SevenPointOneFivePercentSeniorNotesDueSeptember2023Member2023-09-132023-09-130000889900us-gaap:LetterOfCreditMember2025-06-300000889900us-gaap:SuretyBondMember2025-06-300000889900us-gaap:SubsequentEventMember2025-07-232025-07-2300008899002024-02-290000889900pten:StockRepurchasePlanMember2025-01-012025-06-300000889900pten:LongTermIncentivePlanMember2025-01-012025-06-300000889900pten:TimeBasedRestrictedStockUnitsMember2024-12-310000889900pten:PerformanceBasedRestrictedStockUnitsMember2024-12-310000889900us-gaap:RestrictedStockUnitsRSUMember2024-12-310000889900pten:TimeBasedRestrictedStockUnitsMember2025-01-012025-06-300000889900pten:PerformanceBasedRestrictedStockUnitsMember2025-01-012025-06-300000889900us-gaap:RestrictedStockUnitsRSUMember2025-01-012025-06-300000889900pten:TimeBasedRestrictedStockUnitsMember2025-06-300000889900pten:PerformanceBasedRestrictedStockUnitsMember2025-06-300000889900us-gaap:RestrictedStockUnitsRSUMember2025-06-300000889900pten:TimeBasedRestrictedStockUnitsCashSettledMember2024-12-310000889900pten:TimeBasedRestrictedStockUnitsCashSettledMember2025-01-012025-06-300000889900pten:TimeBasedRestrictedStockUnitsCashSettledMember2025-06-300000889900pten:RestrictedStockUnitsCashSettledMember2025-06-300000889900pten:RestrictedStockUnitsCashSettledMember2025-01-012025-06-300000889900us-gaap:PerformanceSharesMember2025-01-012025-06-300000889900us-gaap:PerformanceSharesMembersrt:MinimumMemberpten:A2025TSRPerformanceUnitsMember2025-01-012025-06-300000889900us-gaap:PerformanceSharesMembersrt:MaximumMemberpten:A2025TSRPerformanceUnitsMember2025-01-012025-06-300000889900us-gaap:PerformanceSharesMemberus-gaap:ShareBasedCompensationAwardTrancheOneMember2025-01-012025-06-300000889900us-gaap:PerformanceSharesMemberus-gaap:ShareBasedCompensationAwardTrancheTwoMember2025-01-012025-06-300000889900us-gaap:PerformanceSharesMemberus-gaap:ShareBasedCompensationAwardTrancheThreeMember2025-01-012025-06-300000889900pten:A2025FCFPerformanceUnitsMemberus-gaap:PerformanceSharesMember2025-01-012025-06-300000889900us-gaap:PerformanceSharesMembersrt:MinimumMemberpten:A2025FCFPerformanceUnitsMember2025-01-012025-06-300000889900us-gaap:PerformanceSharesMembersrt:MaximumMemberpten:A2025FCFPerformanceUnitsMember2025-01-012025-06-300000889900pten:PerformanceUnitsShareSettledMember2024-12-310000889900pten:PerformanceUnitsCashSettledMember2024-12-310000889900pten:PerformanceUnitsShareSettledMember2025-01-012025-06-300000889900pten:PerformanceUnitsCashSettledMember2025-01-012025-06-300000889900pten:PerformanceUnitsShareSettledMember2025-06-300000889900pten:PerformanceUnitsCashSettledMember2025-06-300000889900us-gaap:PerformanceSharesMember2025-06-300000889900us-gaap:RestrictedStockUnitsRSUMember2025-04-012025-06-300000889900us-gaap:RestrictedStockUnitsRSUMember2024-04-012024-06-300000889900us-gaap:RestrictedStockUnitsRSUMember2024-01-012024-06-300000889900pten:PerformanceUnitsTSRMember2025-04-012025-06-300000889900pten:PerformanceUnitsTSRMember2024-04-012024-06-300000889900pten:PerformanceUnitsTSRMember2025-01-012025-06-300000889900pten:PerformanceUnitsTSRMember2024-01-012024-06-300000889900pten:PerformanceUnitsFCFMember2025-04-012025-06-300000889900pten:PerformanceUnitsFCFMember2024-04-012024-06-300000889900pten:PerformanceUnitsFCFMember2025-01-012025-06-300000889900pten:PerformanceUnitsFCFMember2024-01-012024-06-300000889900pten:ShareSettledAwardsMember2025-04-012025-06-300000889900pten:ShareSettledAwardsMember2024-04-012024-06-300000889900pten:ShareSettledAwardsMember2025-01-012025-06-300000889900pten:ShareSettledAwardsMember2024-01-012024-06-300000889900pten:RestrictedStockUnitsCashSettledMember2025-04-012025-06-300000889900pten:RestrictedStockUnitsCashSettledMember2024-04-012024-06-300000889900pten:RestrictedStockUnitsCashSettledMember2024-01-012024-06-300000889900pten:PerformanceUnitsCashSettledMember2025-04-012025-06-300000889900pten:PerformanceUnitsCashSettledMember2024-04-012024-06-300000889900pten:PerformanceUnitsCashSettledMember2024-01-012024-06-300000889900pten:CashSettledAwardsMember2025-04-012025-06-300000889900pten:CashSettledAwardsMember2024-04-012024-06-300000889900pten:CashSettledAwardsMember2025-01-012025-06-300000889900pten:CashSettledAwardsMember2024-01-012024-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingServicesMember2025-04-012025-06-300000889900us-gaap:OperatingSegmentsMemberpten:CompletionsServicesMember2025-04-012025-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingProductsMemberMember2025-04-012025-06-300000889900us-gaap:OperatingSegmentsMember2025-04-012025-06-300000889900us-gaap:MaterialReconcilingItemsMember2025-04-012025-06-300000889900us-gaap:CorporateNonSegmentMember2025-04-012025-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingServicesMember2024-04-012024-06-300000889900us-gaap:OperatingSegmentsMemberpten:CompletionsServicesMember2024-04-012024-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingProductsMemberMember2024-04-012024-06-300000889900us-gaap:OperatingSegmentsMember2024-04-012024-06-300000889900us-gaap:MaterialReconcilingItemsMember2024-04-012024-06-300000889900us-gaap:CorporateNonSegmentMember2024-04-012024-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingServicesMember2025-01-012025-06-300000889900us-gaap:OperatingSegmentsMemberpten:CompletionsServicesMember2025-01-012025-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingProductsMemberMember2025-01-012025-06-300000889900us-gaap:OperatingSegmentsMember2025-01-012025-06-300000889900us-gaap:MaterialReconcilingItemsMember2025-01-012025-06-300000889900us-gaap:CorporateNonSegmentMember2025-01-012025-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingServicesMember2024-01-012024-06-300000889900us-gaap:OperatingSegmentsMemberpten:CompletionsServicesMember2024-01-012024-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingProductsMemberMember2024-01-012024-06-300000889900us-gaap:OperatingSegmentsMember2024-01-012024-06-300000889900us-gaap:MaterialReconcilingItemsMember2024-01-012024-06-300000889900us-gaap:CorporateNonSegmentMember2024-01-012024-06-300000889900us-gaap:OperatingSegmentsMemberpten:CompletionServicesMember2025-04-012025-06-300000889900us-gaap:OperatingSegmentsMemberpten:CompletionServicesMember2024-04-012024-06-300000889900us-gaap:OperatingSegmentsMemberpten:CompletionServicesMember2025-01-012025-06-300000889900us-gaap:OperatingSegmentsMemberpten:CompletionServicesMember2024-01-012024-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingProductsMember2025-04-012025-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingProductsMember2024-04-012024-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingProductsMember2025-01-012025-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingProductsMember2024-01-012024-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingServicesMember2025-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingServicesMember2024-12-310000889900us-gaap:OperatingSegmentsMemberpten:CompletionServicesMember2025-06-300000889900us-gaap:OperatingSegmentsMemberpten:CompletionServicesMember2024-12-310000889900us-gaap:OperatingSegmentsMemberpten:DrillingProductsMember2025-06-300000889900us-gaap:OperatingSegmentsMemberpten:DrillingProductsMember2024-12-310000889900us-gaap:OperatingSegmentsMember2025-06-300000889900us-gaap:OperatingSegmentsMember2024-12-310000889900us-gaap:MaterialReconcilingItemsMember2025-06-300000889900us-gaap:MaterialReconcilingItemsMember2024-12-310000889900us-gaap:CorporateNonSegmentMember2025-06-300000889900us-gaap:CorporateNonSegmentMember2024-12-310000889900pten:ThreePointNineFivePercentSeniorNotesDue2028Memberus-gaap:CarryingReportedAmountFairValueDisclosureMember2025-06-300000889900pten:ThreePointNineFivePercentSeniorNotesDue2028Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2025-06-300000889900pten:ThreePointNineFivePercentSeniorNotesDue2028Memberus-gaap:CarryingReportedAmountFairValueDisclosureMember2024-12-310000889900pten:ThreePointNineFivePercentSeniorNotesDue2028Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2024-12-310000889900pten:FivePointOneFivePercentSeniorNotesDue2029Memberus-gaap:CarryingReportedAmountFairValueDisclosureMember2025-06-300000889900pten:FivePointOneFivePercentSeniorNotesDue2029Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2025-06-300000889900pten:FivePointOneFivePercentSeniorNotesDue2029Memberus-gaap:CarryingReportedAmountFairValueDisclosureMember2024-12-310000889900pten:FivePointOneFivePercentSeniorNotesDue2029Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2024-12-310000889900pten:SevenPointOneFivePercentSeniorNotesDueSeptember2033Memberus-gaap:CarryingReportedAmountFairValueDisclosureMember2025-06-300000889900pten:SevenPointOneFivePercentSeniorNotesDueSeptember2033Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2025-06-300000889900pten:SevenPointOneFivePercentSeniorNotesDueSeptember2033Memberus-gaap:CarryingReportedAmountFairValueDisclosureMember2024-12-310000889900pten:SevenPointOneFivePercentSeniorNotesDueSeptember2033Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2024-12-310000889900pten:EquipmentLoansDueTwoThousandTwentyFiveMemberus-gaap:CarryingReportedAmountFairValueDisclosureMember2025-06-300000889900pten:EquipmentLoansDueTwoThousandTwentyFiveMemberus-gaap:EstimateOfFairValueFairValueDisclosureMember2025-06-300000889900pten:EquipmentLoansDueTwoThousandTwentyFiveMemberus-gaap:CarryingReportedAmountFairValueDisclosureMember2024-12-310000889900pten:EquipmentLoansDueTwoThousandTwentyFiveMemberus-gaap:EstimateOfFairValueFairValueDisclosureMember2024-12-310000889900us-gaap:CarryingReportedAmountFairValueDisclosureMember2025-06-300000889900us-gaap:EstimateOfFairValueFairValueDisclosureMember2025-06-300000889900us-gaap:CarryingReportedAmountFairValueDisclosureMember2024-12-310000889900us-gaap:EstimateOfFairValueFairValueDisclosureMember2024-12-310000889900pten:EquipmentLoansMemberus-gaap:FairValueInputsLevel2Member2025-06-300000889900pten:EquipmentLoansMemberus-gaap:FairValueInputsLevel2Member2024-12-310000889900us-gaap:FairValueInputsLevel2Memberpten:ThreePointNineFivePercentSeniorNotesDue2028Memberus-gaap:MarketApproachValuationTechniqueMemberpten:MeasurementInputImpliedMarketRateMember2025-06-300000889900us-gaap:FairValueInputsLevel2Memberpten:ThreePointNineFivePercentSeniorNotesDue2028Memberus-gaap:MarketApproachValuationTechniqueMemberpten:MeasurementInputImpliedMarketRateMember2024-12-310000889900us-gaap:FairValueInputsLevel2Memberpten:FivePointOneFivePercentSeniorNotesDue2029Memberus-gaap:MarketApproachValuationTechniqueMemberpten:MeasurementInputImpliedMarketRateMember2025-06-300000889900us-gaap:FairValueInputsLevel2Memberpten:FivePointOneFivePercentSeniorNotesDue2029Memberus-gaap:MarketApproachValuationTechniqueMemberpten:MeasurementInputImpliedMarketRateMember2024-12-310000889900us-gaap:FairValueInputsLevel2Memberpten:SevenPointOneFivePercentSeniorNotesDueSeptember2033Memberus-gaap:MarketApproachValuationTechniqueMemberpten:MeasurementInputImpliedMarketRateMember2025-06-300000889900us-gaap:FairValueInputsLevel2Memberpten:SevenPointOneFivePercentSeniorNotesDueSeptember2033Memberus-gaap:MarketApproachValuationTechniqueMemberpten:MeasurementInputImpliedMarketRateMember2024-12-310000889900us-gaap:FairValueInputsLevel2Memberpten:EquipmentLoansDueTwoThousandTwentyFiveMemberus-gaap:MarketApproachValuationTechniqueMemberpten:MeasurementInputImpliedMarketRateMember2025-06-300000889900us-gaap:FairValueInputsLevel2Memberpten:EquipmentLoansDueTwoThousandTwentyFiveMemberus-gaap:MarketApproachValuationTechniqueMemberpten:MeasurementInputImpliedMarketRateMember2024-12-31

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________

Form 10-Q

______________________

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

For the quarterly period ended June 30, 2025

or

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

For the transition period from                      to

Commission file number 1-39270

______________________

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)

______________________

Delaware						75-2504748
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)
10713 W. Sam Houston Pkwy N, Suite 800 Houston, Texas						77064
(Address of principal executive offices)						(Zip Code)

(281) 765-7100

(Registrant’s telephone number, including area code)

N/A

(Former name, former address and former fiscal year, if changed since last report)

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

Title of each class

Trading Symbol

Name of each exchange on which registered

Common Stock, $0.01 Par Value

PTEN

The Nasdaq Global Select Market

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 þ    No o

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 (section 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 þ    No o

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

Large accelerated filer

þ

Accelerated filer

o

Smaller reporting company

o

Non-accelerated filer

o

Emerging growth company

o

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

385,167,502 shares of common stock, $0.01 par value, as of July 23, 2025.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

			PART I — FINANCIAL INFORMATION
						Page
ITEM 1.			Financial Statements
			Unaudited condensed consolidated balance sheets			3
			Unaudited condensed consolidated statements of operations			4
			Unaudited condensed consolidated statements of comprehensive income			5
			Unaudited condensed consolidated statements of changes in stockholders’ equity			6
			Unaudited condensed consolidated statements of cash flows			7
			Notes to unaudited condensed consolidated financial statements			8
ITEM 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations			27
ITEM 3.			Quantitative and Qualitative Disclosures About Market Risk			43
ITEM 4.			Controls and Procedures			44
			PART II — OTHER INFORMATION
ITEM 1.			Legal Proceedings			45
ITEM 2.			Unregistered Sales of Equity Securities and Use of Proceeds			45
ITEM 5.			Other Information			46
ITEM 6.			Exhibits			47
Signature

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

The following unaudited condensed consolidated financial statements include all adjustments which are, in the opinion of management, necessary for a fair statement of the results for the interim periods presented.

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands, except share data)

			June 30, 2025						December 31, 2024
ASSETS
Current assets:
Cash, cash equivalents and restricted cash			$	185,891					$	241,293
Accounts receivable, net of allowance for credit losses of $14,282 and $15,047 at   June 30, 2025 and December 31, 2024, respectively			770,901						763,806
Inventory			163,687						167,023
Other current assets			120,644						123,193
Total current assets			1,241,123						1,295,315
Property and equipment, net			2,835,432						3,010,342
Operating lease right of use asset			41,686						44,385
Finance lease right of use asset			22,671						27,018
Goodwill			487,388						487,388
Intangible assets, net			871,950						929,610
Deposits on equipment purchases			19,017						15,699
Other assets			56,353						23,709
Total assets			$	5,575,620					$	5,833,466
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable			$	426,509					$	421,318
Accrued liabilities			261,653						385,751
Operating lease liability			15,083						13,322
Finance lease liability			13,227						15,214
Current maturities of long-term debt			—						6,388
Total current liabilities			716,472						841,993
Long-term operating lease liability			29,591						34,305
Long-term finance lease liability			8,573						10,216
Long-term debt, net of debt discount and issuance costs of $7,002 and $7,637 at   June 30, 2025 and December 31, 2024, respectively			1,220,398						1,219,770
Deferred tax liabilities, net			240,142						238,097
Other liabilities			11,771						13,241
Total liabilities			2,226,947						2,357,622
Commitments and contingencies (see Note 9)
Stockholders’ equity:
Common stock, par value $0.01; authorized 800,000,000 shares with 523,544,388 and   520,784,783 issued and 385,155,678 and 387,344,755 outstanding at June 30, 2025   and December 31, 2024, respectively			5,234						5,206
Additional paid-in capital			6,475,445						6,453,606
Retained deficit			(1,150,176)						(1,039,338)
Accumulated other comprehensive loss			(1,025)						(2,584)
Treasury stock, at cost, 138,388,710 and 133,440,028 shares at June 30, 2025 and   December 31, 2024, respectively			(1,987,133)						(1,951,067)
Total stockholders’ equity attributable to controlling interests			3,342,345						3,465,823
Noncontrolling interest			6,328						10,021
Total equity			3,348,673						3,475,844
Total liabilities and stockholders’ equity			$	5,575,620					$	5,833,466

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

3

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands, except per share data)

			Three Months Ended June 30,												Six Months Ended June 30,
			2025						2024						2025						2024
Operating revenues:
Drilling Services			$	403,805					$	440,289					$	816,665					$	897,862
Completion Services			719,332						805,373						1,485,412						1,750,370
Drilling Products			88,390						86,054						174,053						176,027
Other			7,793						16,478						23,727						34,295
Total operating revenues			1,219,320						1,348,194						2,499,857						2,858,554
Operating costs and expenses:
Drilling Services			254,772						261,497						502,401						533,234
Completion Services			619,083						653,240						1,276,764						1,398,834
Drilling Products			49,335						46,147						96,275						94,777
Other			6,173						10,280						15,337						21,458
Depreciation, depletion, amortization and impairment			261,858						267,638						493,724						542,594
Selling, general and administrative			64,108						64,578						131,038						129,562
Merger and integration expense			488						10,645						920						22,878
Other operating expense (income), net			(7,011)						(11,059)						(4,061)						(17,010)
Total operating costs and expenses			1,248,806						1,302,966						2,512,398						2,726,327
Operating income (loss)			(29,486)						45,228						(12,541)						132,227
Other income (expense):
Interest income			1,272						1,867						2,736						4,056
Interest expense, net of amount capitalized			(17,645)						(17,913)						(35,342)						(36,248)
Other income (expense)			(1,644)						224						324						1,074
Total other expense			(18,017)						(15,822)						(32,282)						(31,118)
Income (loss) before income taxes			(47,503)						29,406						(44,823)						101,109
Income tax expense			1,194						17,785						2,584						37,782
Net income (loss)			(48,697)						11,621						(47,407)						63,327
Net income attributable to noncontrolling interest			447						544						732						1,015
Net income (loss) attributable to common stockholders			$	(49,144)					$	11,077					$	(48,139)					$	62,312
Net income (loss) attributable to common stockholder per common share:
Basic			$	(0.13)					$	0.03					$	(0.12)					$	0.15
Diluted			$	(0.13)					$	0.03					$	(0.12)					$	0.15
Weighted average number of common shares outstanding:
Basic			385,365						399,558						385,940						403,870
Diluted			385,365						399,558						385,940						403,870
Cash dividends per common share			$	0.08					$	0.08					$	0.16					$	0.16

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

4

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited, in thousands)

			Three Months Ended June 30,												Six Months Ended June 30,
			2025						2024						2025						2024
Net income (loss)			$	(48,697)					$	11,621					$	(47,407)					$	63,327
Other comprehensive income (loss):
Foreign currency translation adjustment, net of taxes of $0 for    all periods			1,848						(127)						1,559						(1,120)
Comprehensive income (loss)			(46,849)						11,494						(45,848)						62,207
Less: comprehensive income attributable to noncontrolling interest			447						544						732						1,015
Comprehensive income (loss) attributable to common stockholders			$	(47,296)					$	10,950					$	(46,580)					$	61,192

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

5

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(unaudited, in thousands)

			Common Stock												Additional Paid-in Capital						Retained Deficit						Accumulated Other Comprehensive Income (Loss)						Treasury Stock						Noncontrolling Interest						Total
			Number of Shares						Amount
Balance, December 31, 2024			520,785						$	5,206					$	6,453,606					$	(1,039,338)					$	(2,584)					$	(1,951,067)					$	10,021					$	3,475,844
Net income			—						—						—						1,005						—						—						285						1,290
Distributions to noncontrolling interest			—						—						—						—						—						—						(1,892)						(1,892)
Foreign currency translation adjustment			—						—						—						—						(289)						—						—						(289)
Vesting of restricted stock units			970						10						(10)						—						—						—						—						—
Stock-based compensation			—						—						12,289						—						—						—						—						12,289
Payment of cash dividends ($0.08 per share)			—						—						—						(30,877)						—						—						—						(30,877)
Dividend equivalents			—						—						—						(665)						—						—						—						(665)
Purchase of treasury stock			—						—						—						—						—						(20,295)						—						(20,295)
Balance, March 31, 2025			521,755						$	5,216					$	6,465,885					$	(1,069,875)					$	(2,873)					$	(1,971,362)					$	8,414					$	3,435,405
Net income (loss)			—						—						—						(49,144)						—						—						447						(48,697)
Distributions to noncontrolling interest			—						—						—						—						—						—						(2,533)						(2,533)
Foreign currency translation adjustment			—						—						—						—						1,848						—						—						1,848
Vesting of restricted stock units			1,789						18						(18)						—						—						—						—						—
Stock-based compensation			—						—						9,578						—						—						—						—						9,578
Payment of cash dividends ($0.08 per share)			—						—						—						(30,742)						—						—						—						(30,742)
Dividend equivalents			—						—						—						(415)						—						—						—						(415)
Purchase of treasury stock			—						—						—						—						—						(15,771)						—						(15,771)
Balance, June 30, 2025			523,544						$	5,234					$	6,475,445					$	(1,150,176)					$	(1,025)					$	(1,987,133)					$	6,328					$	3,348,673

			Common Stock												Additional Paid-in Capital						Retained  Earnings						Accumulated Other Comprehensive Income (Loss)						Treasury Stock						Noncontrolling Interest						Total
			Number of Shares						Amount
Balance, December 31, 2023			516,775						$	5,166					$	6,407,294					$	57,035					$	472					$	(1,657,675)					$	8,389					$	4,820,681
Net income			—						—						—						51,235						—						—						471						51,706
Foreign currency translation adjustment			—						—						—						—						(993)						—						—						(993)
Vesting of restricted stock units			1,363						14						(14)						—						—						—						—						—
Stock-based compensation			—						—						12,051						—						—						—						—						12,051
Payment of cash dividends ($0.08 per share)			—						—						—						(32,553)						—						—						—						(32,553)
Dividend equivalents			—						—						—						(422)						—						—						—						(422)
Purchase of treasury stock			—						—						—						—						—						(98,613)						—						(98,613)
Balance, March 31, 2024			518,138						$	5,180					$	6,419,331					$	75,295					$	(521)					$	(1,756,288)					$	8,860					$	4,751,857
Net income			—						—						—						11,077						—						—						544						11,621
Foreign currency translation adjustment			—						—						—						—						(127)						—						—						(127)
Issuance of restricted stock			719						8						(8)						—						—						—						—						—
Vesting of restricted stock units			1,647						17						(17)						—						—						—						—						—
Stock-based compensation			—						—						10,813						—						—						—						—						10,813
Payment of cash dividends ($0.08 per share)			—						—						—						(31,815)						—						—						—						(31,815)
Dividend equivalents			—						—						—						(348)						—						—						—						(348)
Purchase of treasury stock			—						—						—						—						—						(133,487)						—						(133,487)
Balance, June 30, 2024			520,504						$	5,205					$	6,430,119					$	54,209					$	(648)					$	(1,889,775)					$	9,404					$	4,608,514

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

6

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)

			Six Months Ended June 30,
			2025						2024
Cash flows from operating activities:
Net income (loss)			$	(47,407)					$	63,327
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and impairment			493,724						542,594
Deferred income tax expense			1,704						36,252
Stock-based compensation			21,867						22,864
Net gain on asset disposals			(973)						(6,689)
Other			(1,972)						6,087
Changes in operating assets and liabilities:
Accounts receivable			(6,902)						101,645
Inventory			2,316						(9,779)
Other current assets			(1,980)						(22,164)
Other assets			3,236						15,999
Accounts payable			17,132						(45,696)
Accrued liabilities			(125,396)						(121,347)
Other liabilities			(7,459)						(19,680)
Net cash provided by operating activities			347,890						563,413
Cash flows from investing activities:
Purchases of property and equipment			(306,037)						(357,449)
Proceeds from disposal of assets, including insurance recoveries			28,344						9,321
Other			(11,514)						(1,376)
Net cash used in investing activities			(289,207)						(349,504)
Cash flows from financing activities:
Purchases of treasury stock			(35,849)						(230,202)
Dividends paid			(61,619)						(64,368)
Payments of finance leases			(4,432)						(31,905)
Other			(10,820)						(6,063)
Net cash used in financing activities			(112,720)						(332,538)
Effect of foreign exchange rate changes on cash, cash equivalents and restricted cash			(1,365)						985
Net decrease in cash, cash equivalents and restricted cash			(55,402)						(117,644)
Cash, cash equivalents and restricted cash at beginning of period			241,293						192,680
Cash, cash equivalents and restricted cash at end of period			$	185,891					$	75,036
Supplemental disclosure of cash flow information:
Net cash paid during the period for:
Interest, net of capitalized interest of $443 in 2025 and $527 in 2024			$	(33,396)					$	(34,341)
Income taxes			(3,106)						(12,741)
Non-cash investing and financing activities:
Net decrease in payables for purchases of property and equipment			$	(12,115)					$	(12,161)
Purchases of property and equipment through exchange of lease right of use asset			1,007						26,133
Derecognition of right of use asset			(755)						(31,179)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

7

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation

Basis of presentation — The unaudited interim condensed consolidated financial statements include the accounts of Patterson-UTI Energy, Inc. and its wholly-owned subsidiaries and consolidating interest of a joint venture (collectively referred to herein as “we,” “us,” “our,” “ours” and like terms). All intercompany accounts and transactions have been eliminated. Patterson-UTI Energy, Inc. conducts its business operations through its wholly-owned subsidiaries and has no employees or independent operations. Certain immaterial prior year amounts have been reclassified to conform to current year presentation.

The U.S. dollar is the reporting currency and functional currency for most of our operations except certain of our foreign subsidiaries, which use their local currencies as their functional currency. Assets and liabilities of these foreign subsidiaries are translated into U.S. dollars using the exchange rates in effect as of the balance sheet date. The effects of these translation adjustments are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity.

The unaudited interim condensed consolidated financial statements have been prepared by us pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been omitted pursuant to such rules and regulations, although we believe the disclosures included either on the face of the financial statements or herein are sufficient to make the information presented not misleading. In the opinion of management, all recurring adjustments considered necessary for a fair statement of the information in conformity with GAAP have been included. The unaudited condensed consolidated balance sheet as of December 31, 2024, as presented herein, was derived from our audited consolidated balance sheet but does not include all disclosures required by GAAP. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2024 (our “Annual Report”). The results of operations for the three and six months ended June 30, 2025 are not necessarily indicative of the results to be expected for the full year.

There have been no material changes to our critical accounting policies from those disclosed in our Annual Report.

Restricted cash — Restricted cash includes amounts restricted as cash collateral for the issuance of standby letters of credit.

The following table provides a reconciliation of cash and restricted cash reported within the unaudited condensed consolidated balance sheets that sum to the total of such amounts shown in the unaudited condensed statements of cash flows for the six months ended June 30, 2025 and 2024:

			Six Months Ended June 30,
			2025						2024
Cash and cash equivalents			$	183,768					$	72,444
Restricted cash			2,123						2,592
Total cash, cash equivalents and restricted cash			$	185,891					$	75,036

Recently Adopted Accounting Standards — In November 2023, the FASB issued an accounting standards update to improve reportable segment disclosure requirements and enhance disclosures about significant segment expenses. We adopted this new accounting pronouncement effective January 1, 2024 and expanded our consolidated financial statement disclosures in order to comply with the update. See Note 14 for details.

Recently Issued Accounting Standards — In December 2023, the FASB issued an accounting standards update to improve income tax disclosure requirements. We plan to adopt this accounting pronouncement during fiscal year 2025, with the first disclosure enhancements to be reflected in our Annual Report on Form 10-K for the year ending December 31, 2025. We are currently evaluating the impact this pronouncement will have on our disclosures.

In November 2024, the FASB issued guidance expanding disclosure requirements related to certain income statement expenses, which requires public entities to disclose additional information about specific expense categories in the notes to the financial statements on an interim and annual basis. This guidance is effective for annual reporting periods beginning after December 15, 2026 and interim periods beginning after December 15, 2027, with early adoption permitted. We are currently evaluating the effect of this pronouncement on our disclosures.

8

2. Revenues

ASC Topic 606 Revenue from Contracts with Customers

Drilling Services and Completion Services — revenue is recognized based on our customers’ ability to benefit from our services in an amount that reflects the consideration we expect to receive in exchange for those services. This typically happens when the service is performed. The services we provide represent a series of distinct services, generally provided daily, that are substantially the same, with the same pattern of transfer to the customer. Because our customers benefit equally throughout the service period, generally measured in days, and our efforts in providing services are incurred relatively evenly over the period of performance, revenue is recognized as we provide services to the customer.

Drilling Services revenue primarily consists of daywork drilling contracts for which related revenues and expenses are recognized as services are performed. For certain contracts, we receive payments for the mobilization of rigs and other drilling equipment. We defer revenue and related direct operating expense related to mobilizations and recognize those revenues and expenses on a straight-line basis as drilling services are provided. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred and are recorded in Drilling Services operating expense in the Consolidated Statements of Operations and Comprehensive Income (Loss). For certain contracts, we are also entitled to early termination payments if our customers choose to terminate a contract prior to the expiration of the contractual term. We recognize revenue associated with early termination payments when all contractual requirements related to early termination payments have been met.

Completion Services revenue consists of services and products related to our suite of completion businesses, including hydraulic fracturing, completion support services, wireline and pumpdown services, and cementing. These services are provided pursuant to contractual arrangements, including pricing agreements. Revenue from these services is earned as services are rendered, which is generally on a per stage or fixed monthly rate, except for our cementing services. All revenue is recognized when a contract with a customer exists, the performance obligations under the contract have been satisfied over time, the amount to which we have the right to invoice has been determined and collectability of amounts subject to invoice is probable. Contract fulfillment costs, such as mobilization costs and shipping and handling costs, are expensed as incurred and are recorded in Completion Services operating expense in the Consolidated Statements of Operations and Comprehensive Income (Loss). To the extent fulfillment costs are considered separate performance obligations that are billable to the customer, the amounts billed are recorded as revenue in the Consolidated Statements of Operations and Comprehensive Income (Loss).

Once a stage has been completed or products and services have been provided, a field ticket is created that includes charges for the service performed and the chemicals, proppant, and compressed natural gas consumed during the course of the service. The field ticket may also include charges for the mobilization of the equipment and inventory to the location, any additional equipment used on the job, and other miscellaneous items. The field ticket represents the amounts to which we have the right to invoice and to recognize as revenue.

A portion of our contracts contain variable consideration; however, this variable consideration is typically unknown at the time of contract inception, and is not known until the job is complete, at which time the variability is resolved. Examples of variable consideration include the number of hours that will be incurred and the amount of consumables (such as chemicals and proppants) that will be used to complete a job.

Revenue is presented net of any sales tax charged to the customer that we are required to remit to local or state governmental taxing authorities. Reimbursements for the purchase of supplies, equipment, personnel services, shipping and other services that are provided at the request of our customers are recorded as revenue when incurred. The related costs are recorded as operating expenses when incurred.

ASC Topic 842 Revenue from Equipment Rentals

Drilling Products Revenue — revenues are primarily generated from the rental of drilling equipment, comprised of drill bits and downhole tools. These arrangements provide the customer with the right to control the use of the identified asset. Generally, the lease terms in such arrangements are for periods of two to three days and do not provide customers with options to purchase the underlying asset.

Other — we are a non-operating working interest owner of oil and natural gas assets primarily located in Texas and New Mexico. The ownership terms are outlined in joint operating agreements for each well between the operator of the well and the various interest owners, including us, who are considered non-operators of the well. We receive revenue each period for our working interest in the well during the period.

9

Accounts Receivable and Contract Liabilities

Accounts receivable is our right to consideration once it becomes unconditional. Payment terms typically range from 30 to 60 days.

We do not have any significant contract asset balances. Contract liabilities include prepayments received from customers prior to the requested services being completed. Once the services are complete and have been invoiced, the prepayment is applied against the customer’s account to offset the accounts receivable balance. Also included in contract liabilities are payments received from customers for reactivation or initial mobilization of newly constructed or upgraded rigs that were moved on location to the initial well site. These payments are allocated to the overall performance obligation and amortized over the initial term of the contract. Total contract liability balances were $4.8 million and $75.6 million as of June 30, 2025 and December 31, 2024, respectively. We recognized $70.5 million of revenue during the six months ended June 30, 2025 that was included in the contract liability balance at the beginning of the period. Revenue related to our contract liabilities balance is expected to be recognized through 2028. The $4.5 million current portion of our contract liability balance is included in “Accrued liabilities” and the $0.3 million noncurrent portion of our contract liability balance is included in “Other liabilities” in our consolidated balance sheets.

Contract Costs

Costs incurred for newly constructed rigs or rig upgrades based on a contract with a customer are considered capital improvements and are capitalized to drilling equipment and depreciated over the estimated useful life of the asset.

Remaining Performance Obligations

We maintain a backlog of commitments for contract drilling services under term contracts, which we define as contracts with a duration of six months or more. Our contract drilling backlog in the United States as of June 30, 2025 was approximately $312 million. Approximately 9% of our total contract drilling backlog in the United States at June 30, 2025 is reasonably expected to remain at June 30, 2026. We generally calculate our backlog by multiplying the dayrate under our term drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to fees for other services such as for mobilization, other than initial mobilization, demobilization and customer reimbursables, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving or incurring maintenance and repair time in excess of what is permitted under the drilling contract. For contracts that contain variable dayrate pricing, our backlog calculation uses the dayrate in effect for periods where the dayrate is fixed, and, for periods that remain subject to variable pricing, uses commodity pricing or other related indices in effect at June 30, 2025. In addition, our term drilling contracts are generally subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. For contracts on which we have received notice for the rig to be placed on standby, our backlog calculation uses the standby rate for the period over which we expect to receive the standby rate. For contracts on which we have received an early termination notice, our backlog calculation includes the early termination rate, instead of the dayrate, for the period over which we expect to receive the lower rate. Please see “Our current backlog of contract drilling revenue may decline and may not ultimately be realized, as fixed-term contracts may in certain instances be terminated without an early termination payment” included in Item 1A of our Annual Report.

3. Inventory

Inventory consisted of the following at June 30, 2025 and December 31, 2024 (in thousands):

			June 30, 2025						December 31, 2024
Raw materials and supplies			$	125,555					$	121,694
Work-in-process			7,596						6,681
Finished goods			30,536						38,648
Inventory			$	163,687					$	167,023

10

4. Other Current Assets

Other current assets consisted of the following at June 30, 2025 and December 31, 2024 (in thousands):

			June 30, 2025						December 31, 2024
Federal and state income taxes receivable			$	27,660					$	24,777
Workers’ compensation receivable			26,474						33,240
Prepaid expenses			43,388						34,004
Other			23,122						31,172
Other current assets			$	120,644					$	123,193

5. Property and Equipment

Property and equipment consisted of the following at June 30, 2025 and December 31, 2024 (in thousands):

			June 30, 2025						December 31, 2024
Equipment			$	8,252,369					$	8,416,063
Oil and natural gas properties			243,451						243,663
Buildings			244,514						248,739
Rental equipment			142,205						136,256
Land			41,642						37,847
Total property and equipment			8,924,181						9,082,568
Less accumulated depreciation, depletion, amortization and impairment			(6,088,749)						(6,072,226)
Property and equipment, net			$	2,835,432					$	3,010,342

Depreciation and depletion expense on property and equipment of approximately $199 million and $216 million was recorded in the three months ended June 30, 2025 and 2024, respectively. Depreciation and depletion expense on property and equipment of approximately $399 million and $460 million was recorded in the six months ended June 30, 2025 and 2024, respectively.

During the second quarter of 2025, global economic conditions deteriorated, in part, because of recently enacted and proposed trade policies and tariffs by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs. Additionally, during the second quarter of 2025, OPEC+ countries began phasing out voluntary crude oil production cuts, leading to an increase in global supply. These developments, combined with rising geopolitical tensions—particularly in the Middle East— have heightened uncertainty in global energy markets, which has contributed to a decline in our share price, lowered average crude oil futures prices and increased uncertainty regarding the future economic environment in which we operate.

Negative market indicators such as lower industry-wide drilling rig and pressure pumping fleet count forecasts, increased volatility and margin compression for certain of our asset groups have led to our reduced outlook for activity. The reduction in activity forecasts combined with the recent decline in the market price of our common stock were considered a triggering event indicating certain of our long-lived tangible and intangible assets may be impaired. We deemed it necessary to perform recoverability tests on our hydraulic fracturing asset group within our completion services reporting unit and our Latin American contract drilling asset group during the second quarter of 2025. We estimated future cash flows over the expected remaining life of the primary asset for each asset group. On an undiscounted basis, the expected cash flows exceeded the carrying value of our hydraulic fracturing asset group within our completion services reporting unit, indicating that no impairment was required.

The recoverability test for our Latin American contract drilling asset group indicated that estimated undiscounted cash flows did not exceed its carrying value. Accordingly, we performed an impairment test and estimated the fair value of the asset group using the income approach. Under this approach, we used a discounted cash flow model, which utilized present values of cash flows to estimate fair value. Forecasted cash flows reflected known market conditions in the second quarter of 2025 and management’s anticipated business outlook for the asset group. Future cash flows were projected based on estimates of revenue, gross profit, selling, general and administrative expense, changes in working capital, and capital expenditures. Future cash flows were then discounted using a market-participant, risk-adjusted weighted average cost of capital. Based on the results of the analysis performed, we recorded a $27.8 million impairment charge to Latin American drilling equipment during the three months ended June 30, 2025 in our drilling services segment.

11

While the full effects of recent market developments are yet to be determined, prolonged trade tensions and sustained lower crude oil futures prices could adversely affect our future outlook on activity and profitability. If these conditions persist or deteriorate further, or if other unforeseen macroeconomic conditions emerge, they could negatively impact the expected cash flows used in our recoverability tests for our asset groups. Such changes could result in impairment charges in the future, which could be material to our results of operations and financial statements as a whole.

6. Goodwill and Intangible Assets

Goodwill — During the six months ended June 30, 2025, there were no additions or impairments to goodwill. As of June 30, 2025 and December 31, 2024, our goodwill balance was $487 million.

Goodwill is evaluated at least annually on July 31, or more frequently if impairment indicators arise. Goodwill is tested at the reporting unit level, which is at or one level below our operating segments. We determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors. Any necessary goodwill impairment is determined using a quantitative impairment test. If the resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized for the amount of the shortfall. The fair value of a reporting unit is determined using significant unobservable inputs, or level 3 in the fair value hierarchy. These inputs are based on forecasts and significant judgment.

We determined our drilling products operating segment consists of a single reporting unit to which the goodwill from our 2023 acquisition of Ulterra Drilling Technologies, L.P. was allocated. We determined our completion services operating segment consisted of two reporting units; completion services, which was primarily comprised of our hydraulic fracturing operations and other integrated service offerings, and cementing services.

Goodwill Impairment Assessment — During the second quarter of 2025, we viewed the reduction in activity forecasts combined with the decline in the market price of our common stock as a triggering event that warranted a quantitative assessment for goodwill impairment.

We estimated the fair value of the drilling products and cementing services reporting units using the income approach. Under this approach, we used a discounted cash flow model, which utilized present values of cash flows to estimate fair value. Forecasted cash flows reflected known market conditions in the second quarter of 2025 and the expected market outlook. Future cash flows were projected based on estimates of revenue growth rates, gross profit, selling, general and administrative expense, changes in working capital, and capital expenditures. The terminal period used within the discounted cash flow model consisted of a growth estimate. Future cash flows were then discounted using a market-participant, risk-adjusted weighted average cost of capital. Financial and credit market volatility directly impacts our fair value measurement through the weighted average cost of capital used to determine a discount rate. During times of volatility, significant judgment must be applied to determine whether credit market changes are a short-term or long-term trend.

The forecast for the cementing services reporting unit assumed lower activity in 2026 compared to estimated average activity levels for full year 2025 and moderate growth estimates thereafter. Those estimates were based on future drilling rig count forecasts during the second quarter of 2025 and estimated market share. Based on the results of the goodwill impairment test, the fair value of the cementing services reporting unit exceeded its carrying value with a substantial cushion. Accordingly, no impairment was recorded.

The forecast for the drilling products reporting unit assumed lower activity during 2025 relative to 2024, with growth estimates thereafter. The increases in estimated activity assumed growth in both domestic and international markets. Those growth estimates were based on drilling rig count forecasts and estimated market share. Geopolitical instability in regions in which we expect to maintain and grow market share, an unfavorable legal proceeding outcome, a global decrease in the demand of drilling products or other unforeseen macroeconomic considerations could negatively impact the key assumptions used in our goodwill assessment for our drilling products reporting unit. Based on the results of the goodwill impairment test, the fair value of the drilling products reporting unit exceeded its carrying value by approximately 8%. Accordingly, no impairment was recorded.

12

Intangible Assets — The following table presents the gross carrying amount and accumulated amortization of our intangible assets as of June 30, 2025 and December 31, 2024 (in thousands):

			June 30, 2025																		December 31, 2024
			Gross Carrying Amount						Accumulated Amortization						Net Carrying Amount						Gross Carrying Amount						Accumulated Amortization						Net Carrying Amount
Customer relationships			$	783,182					$	(130,993)					$	652,189					$	782,789					$	(95,785)					$	687,004
Developed technology			202,771						(76,887)						125,884						202,772						(56,562)						146,210
Trade name			101,000						(18,406)						82,594						101,000						(14,097)						86,903
Other			17,250						(5,967)						11,283						12,986						(3,493)						9,493
Intangible assets, net			$	1,104,203					$	(232,253)					$	871,950					$	1,099,547					$	(169,937)					$	929,610

Amortization expense on intangible assets of approximately $31.9 million and $30.9 million was recorded for the three months ended June 30, 2025 and 2024, respectively. Amortization expense on intangible assets of approximately $62.8 million and $61.3 million was recorded for the six months ended June 30, 2025 and 2024, respectively.

7. Accrued Liabilities

Accrued liabilities consisted of the following at June 30, 2025 and December 31, 2024 (in thousands):

			June 30, 2025						December 31, 2024
Salaries, wages, payroll taxes and benefits			$	89,575					$	110,212
Workers’ compensation liability			65,988						73,730
Property, sales, use and other taxes			41,679						54,445
Insurance, other than workers’ compensation			9,095						10,703
Accrued interest payable			17,512						17,484
Deferred revenue			4,467						75,195
Accrued merger and integration expense			2,500						4,723
Other			30,837						39,259
Accrued liabilities			$	261,653					$	385,751

8. Long-Term Debt

Long-term debt consisted of the following at June 30, 2025 and December 31, 2024 (in thousands):

			June 30, 2025						December 31, 2024
3.95% Senior Notes Due 2028			$	482,505					$	482,505
5.15% Senior Notes Due 2029			344,895						344,895
7.15% Senior Notes Due 2033			400,000						400,000
Equipment Loans Due 2025 (1)			—						6,395
			1,227,400						1,233,795
Less deferred financing costs and discounts			(7,002)						(7,637)
Less current portion			—						(6,388)
Total			$	1,220,398					$	1,219,770

(1)The borrowings outstanding under the Equipment Loans were paid off in full in June 2025.

Credit Agreement — On January 31, 2025, we entered into the Second Amended and Restated Credit Agreement with the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, and the other parties thereto (the “Credit Agreement”). The Credit Agreement amended and restated our Amended and Restated Credit Agreement dated as of March 27, 2018. The commitments under the Credit Agreement are $500 million, and the loans and commitments under the Credit Agreement mature on January 31, 2030.

13

The Credit Agreement provides for a committed senior unsecured credit facility that permits aggregate revolving credit borrowings of up to $500 million, with a letter of credit sub-facility of $100 million and a swing line sub-facility that, at any time outstanding, is limited to the lesser of $50 million and the amount of the swing line provider’s unused commitment. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $200 million, not to exceed total commitments of $700 million.

Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate (plus a 0.10% per annum adjustment) or base rate, in each case subject to a 0% floor. The applicable margin on SOFR rate loans varies from 1.25% to 2.25% and the applicable margin on base rate loans varies from 0.25% to 1.25%, in each case determined based on our credit rating. As of June 30, 2025, the applicable margin on SOFR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. A letter of credit fee is payable by us equal to the applicable margin for SOFR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders varies from 0.15% to 0.35% based on our credit rating.

None of our subsidiaries are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt, which does not qualify for certain limited exceptions and is otherwise, in the aggregate with all other similar debt, in excess of Priority Debt (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.

The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that we believe are customary for agreements of this nature, including certain restrictions on our ability and the ability of each of our subsidiaries to grant liens and on the ability of each of our non-guarantor subsidiaries to incur debt. If our credit rating is below investment grade at both Moody’s and S&P, we will become subject to a restricted payment covenant, which would generally require us to have a Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment. Restricted payments include, among other things, dividend payments, repurchases of our common stock, distributions to holders of our common stock or any other payment or other distribution to third parties on account of our or our subsidiaries’ equity interests. Our credit rating is currently investment grade at both credit rating agencies. The Credit Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50% as of the last day of each fiscal quarter. The Credit Agreement generally defines the total debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the end of the most recently ended fiscal quarter. We were in compliance with these covenants at June 30, 2025.

As of June 30, 2025, we had no borrowings outstanding under our Credit Agreement. We had $2.0 million in letters of credit outstanding under the Credit Agreement at June 30, 2025 and, as a result, had available borrowing capacity of approximately $498 million under the Credit Agreement at that date.

2015 Reimbursement Agreement — On March 16, 2015, we entered into a Reimbursement Agreement (as amended from time to time, the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of June 30, 2025, we had $38.1 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any of our letters of credit issued thereunder. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the Prime rate plus 2.00% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts. A letter of credit fee is payable by us equal to 1.50% times the amount of outstanding letters of credit.

We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our or our subsidiaries’ property, then our reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

Pursuant to a Continuing Guaranty dated as of March 16, 2015, our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee

14

payment under the Credit Agreement. None of our subsidiaries are currently required to guarantee payment under the Credit Agreement.

2028 Senior Notes, 2029 Senior Notes and 2033 Senior Notes — On January 19, 2018, we completed an offering of $525 million in aggregate principal amount of 3.95% Senior Notes due 2028 (the “2028 Notes”). On November 15, 2019, we completed an offering of $350 million in aggregate principal amount of 5.15% Senior Notes due 2029 (the “2029 Notes”). On September 13, 2023, we completed an offering of $400 million in aggregate principal amount of 7.15% Senior Notes due 2033 (the “2033 Notes”).

We pay interest on the 2028 Notes on February 1 and August 1 of each year. The 2028 Notes will mature on February 1, 2028. The 2028 Notes bear interest at a rate of 3.95% per annum.

We pay interest on the 2029 Notes on May 15 and November 15 of each year. The 2029 Notes will mature on November 15, 2029. The 2029 Notes bear interest at a rate of 5.15% per annum.

We pay interest on the 2033 Notes on April 1 and October 1 of each year. The 2033 Notes will mature on October 1, 2033. The 2033 Notes bear interest at a rate of 7.15% per annum.

The 2028 Notes, 2029 Notes and 2033 Notes (together, the “Senior Notes”) are our senior unsecured obligations, which rank equally with all of our other existing and future senior unsecured debt and will rank senior in right of payment to all of our other future subordinated debt. The Senior Notes will be effectively subordinated to any of our future secured debt to the extent of the value of the assets securing such debt. In addition, the Senior Notes will be structurally subordinated to the liabilities (including trade payables) of our subsidiaries that do not guarantee the Senior Notes. None of our subsidiaries are currently required to be a guarantor under the Senior Notes. If our subsidiaries guarantee the Senior Notes in the future, such guarantees (the “Guarantees”) will rank equally in right of payment with all of the guarantors’ future unsecured senior debt and senior in right of payment to all of the guarantors’ future subordinated debt. The Guarantees will be effectively subordinated to any of the guarantors’ future secured debt to the extent of the value of the assets securing such debt.

At our option, we may redeem the Senior Notes in whole or in part, at any time or from time to time at a redemption price equal to 100% of the principal amount of such Senior Notes to be redeemed, plus accrued and unpaid interest, if any, on those Senior Notes to the redemption date, plus a “make-whole” premium. Additionally, commencing on November 1, 2027, in the case of the 2028 Notes, on August 15, 2029, in the case of the 2029 Notes, and on July 1, 2033, in the case of the 2033 Notes, at our option, we may redeem the respective Senior Notes in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus accrued and unpaid interest, if any, on those Senior Notes to the applicable redemption date.

The indentures pursuant to which the Senior Notes were issued include covenants that, among other things, limit our and our subsidiaries’ ability to incur certain liens, engage in sale and lease-back transactions or consolidate, merge, or transfer all or substantially all of their assets. These covenants are subject to important qualifications and limitations set forth in the indentures.

Upon the occurrence of a change of control triggering event, as defined in the indentures, each holder of the Senior Notes may require us to purchase all or a portion of such holder’s Senior Notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to, but excluding, the applicable repurchase date.

The indentures also provide for events of default which, if any of them occurs, would permit or require the principal of, premium, if any, and accrued interest, if any, on the Senior Notes to become or to be declared due and payable.

Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of June 30, 2025 (in thousands):

Year ending December 31,
2025			$	—
2026			—
2027			—
2028			482,505
2029			344,895
Thereafter			400,000
Total			$	1,227,400

15

9. Commitments and Contingencies

As of June 30, 2025, we maintained letters of credit in the aggregate amount of $42.1 million primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses that could become payable under the terms of the underlying insurance contracts and compliance with contractual obligations. These letters of credit expire annually at various times during the year and are typically renewed. As of June 30, 2025, no amounts had been drawn under the letters of credit. As of June 30, 2025, we had $37.0 million in surety bond exposure issued as financial assurance on an insurance agreement.

As of June 30, 2025, we had commitments to purchase major equipment totaling approximately $94.8 million.

Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. As of June 30, 2025, the remaining minimum obligation under these agreements was approximately $27.1 million, of which approximately $9.2 million, $13.1 million, and $4.8 million relate to the remainder of 2025, 2026, and 2027, respectively.

Certain subsidiaries we acquired in the Ulterra acquisition are defendants in a claim brought by a subsidiary of NOV Inc. alleging breach of a license agreement related to certain patents. Such subsidiaries have asserted defenses to the claim and are defending vigorously against this claim.

On February 6, 2023, Grant Prideco, Inc., ReedHycalog UK, Ltd. ReedHycalog, LP, National Oilwell Varco, LP (“NOV”) sued Ulterra Drilling Technologies, LP (“Ulterra”) and several other companies in Texas state court. NOV seeks a declaration that United States Patent No. 8,721,752 (the “’752 Patent”) is a “Licensed RH Patent” per the terms of a license agreement between Ulterra and NOV. NOV also alleges a breach of contract based on the license agreement between NOV and Ulterra and seeks allegedly owed royalties since October 22, 2021. NOV also seeks attorney’s fees.

On February 27, 2023, Ulterra filed a plea to the jurisdiction, and subject thereto, an answer, affirmative defenses and counterclaims. Ulterra’s counterclaims include: (i) declaratory judgments of non-infringement of U.S. Pat. No. 7,568,534 and the ’752 patent; (ii) a declaratory judgment of no royalties after Oct. 22, 2021; (iii) a declaratory judgment that certain other identified patents are expired and therefore not infringed after Oct. 22, 2021; and (iv) a declaratory judgment of no breach of contract. On the same day, Ulterra filed a notice of removal in federal court for the Southern District of Texas, Houston Division (SDTX 4:23-cv-00730), as well as a corresponding notice in Texas state court. NOV moved to dismiss and remand the case back to state court. On February 17, 2024, the Court denied NOV’s motion. On March 19, 2024, Ulterra moved for judgment on the pleadings regarding its declaratory judgment that certain other identified patents are expired and therefore not infringed after October 22, 2021. On February 13, 2025, the motion was granted in part and denied in part.

Discovery is closed and dispositive motions are fully briefed. Trial is currently scheduled for October 27, 2025. An unfavorable judgment or resolution of this claim not covered by indemnity could have a material impact on our financial results.

Additionally, we are party to various other legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition, cash flows or results of operations.

10. Stockholders’ Equity

Cash Dividend — On July 23, 2025, our Board of Directors approved a cash dividend on our common stock in the amount of $0.08 per share to be paid on September 15, 2025 to holders of record as of September 2, 2025. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend for any reason, including to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.

Share Repurchases and Acquisitions — In September 2013, our Board of Directors approved a stock buyback program. In February 2024, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for an aggregate of $1.0 billion of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the buyback program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. There is no expiration date associated with the buyback program. As of June 30, 2025, we had remaining authorization to purchase approximately $728 million of our outstanding common stock under the stock buyback program. Shares of stock purchased under the buyback program are held as treasury shares.

16

Treasury stock acquisitions during the six months ended June 30, 2025 were as follows (dollars in thousands):

			Shares						Cost
Treasury shares at January 1, 2025			133,440,028						$	1,951,067
Purchases pursuant to stock buyback program			4,278,723						31,434
Acquisitions pursuant to long-term incentive plans			669,959						4,632
Treasury shares at June 30, 2025			138,388,710						$	1,987,133

11. Stock-based Compensation

We use share-based payments to compensate employees and non-employee directors. We grant incentive awards in the form of restricted stock units (a small portion of which are subject to the achievement of performance conditions) and performance unit awards (which are subject to the achievement of performance conditions). Certain of these incentive awards are share-settled, and certain of these incentive awards are cash-settled. See Note 12 in Notes to consolidated financial statements in Item 8 of our Annual Report for further description of the various types of stock-based compensation awards (other than the 2025 Performance Units, which are described below) and the applicable award terms and accounting.

Stock Options — No stock options have been granted since 2016. Stock option activity from January 1, 2025 to June 30, 2025 follows:

			Underlying Shares						Weighted Average Exercise Price Per Share
Outstanding at January 1, 2025			1,794,005						$	22.26
Exercised			—						$	—
Expired			(616,800)						$	20.33
Outstanding at June 30, 2025			1,177,205						$	23.27
Exercisable at June 30, 2025			1,177,205						$	23.27

Restricted Stock Units (Equity Based) — Share-settled restricted stock unit activity from January 1, 2025 to June 30, 2025 follows:

			Time Based						Performance Based						Weighted Average Grant Date Fair Value Per Share
Non-vested restricted stock units outstanding at January 1, 2025			5,427,657						452,514						$	11.34
Granted			4,429,947						—						$	6.04
Vested			(2,759,605)						—						$	11.43
Forfeited			(113,246)						(1,489)						$	10.32
Non-vested restricted stock units outstanding at June 30, 2025			6,984,753						451,025						$	8.17

As of June 30, 2025, we had unrecognized compensation cost related to our unvested restricted stock units totaling $51.7 million. The weighted-average remaining vesting period for these unvested restricted stock units was 2.26 years as of June 30, 2025.

17

Restricted Stock Units (Liability Based) — A portion of the annual restricted stock unit awards granted in 2025 are cash-settled. Cash-settled restricted stock unit activity from January 1, 2025 to June 30, 2025 follows:

			Time Based
Non-vested cash-settled restricted stock units outstanding at January 1, 2025			13,134
Granted			619,417
Vested			(4,376)
Forfeited			—
Non-vested cash-settled restricted stock units outstanding at June 30, 2025			628,175

As of June 30, 2025, we had unrecognized compensation cost related to our unvested cash-settled restricted stock units totaling $3.6 million. The weighted-average remaining vesting period for these unvested cash-settled restricted stock units was 2.83 years as of June 30, 2025.

Performance Unit Awards — We have granted performance unit awards to certain employees (the “Performance Units”). The Performance Units generally vest over a three-year period based on the achievement of performance goals. Historically, Performance Units have been tied to total shareholder return (“TSR”) achievement as compared to the TSR of a designated peer group, and allow for a payout ranging between 0% and 200% of the target payout. With respect to the Performance Units granted in May 2025, (i) one-half are cash-settled and are otherwise structured similarly to the 2024 Performance Units with vesting tied to our TSR over 1-, 2- and 3-year performance periods (the “2025 TSR Performance Units”), and (ii) one-half are share-settled and tied to our relative free cash flow return over the three-year period commencing January 1, 2025 as compared to the free cash flow return of a designated peer group (“FCF”), and allow for a payout ranging between 0% and 200% of the target payout (the “2025 FCF Performance Units”).

Share-settled Performance Units, excluding the 2025 FCF Performance Units, have vesting terms subject to a market condition and are measured at fair value on the date of grant using a Monte Carlo simulation model. The 2025 TSR Performance Units are cash-settled and are accounted for as liability classified awards and remeasured at fair value using a Monte Carlo simulation model at each reporting period. The 2025 FCF Performance Units are subject to an operational performance condition, with fair value determined based on the average closing price of our common stock over the 20 trading days immediately preceding the grant date. Stock-based compensation expense is subsequently adjusted to reflect the fair value of units expected to vest, based on the likelihood of meeting the performance condition. If the performance condition is not met, any previously recognized compensation expense will be reversed.

Performance Units activity from January 1, 2025 to June 30, 2025 follows:

			Performance Units Share-Settled (at target)						Weighted Average Grant Date Fair Value Per Share						Performance Units Cash-Settled (at target)
Non-vested outstanding at January 1, 2025			1,869,400						$	15.62					—
Granted			743,800						$	5.86					743,800
Performance units settled (1)			(398,500)						$	25.95					—
Forfeited			—						$	—					—
Non-vested outstanding at June 30, 2025			2,214,700						$	10.49					743,800

(1)Share-settled Performance Units granted in 2022 reached the end of their performance period during the six months ended June 30, 2025, and no shares were issued to settle such Performance Units.

As of June 30, 2025, we had unrecognized compensation cost related to our unvested Performance Units totaling $21.2 million. The weighted-average remaining vesting period for these unvested Performance Units was 2.05 years as of June 30, 2025.

18

Stock-Based Compensation Expense — Expense associated with restricted stock units and Performance Unit awards is included in “Selling, general and administrative” in our unaudited condensed consolidated statements of operations. The following table presents stock-based compensation expense for the three and six months ended June 30, 2025 and 2024:

						Three Months Ended June 30,																		Six Months Ended June 30,
Share-settled awards						2025						2024												2025						2024
Restricted stock units						$	7,512					$	8,681											$	17,398					$	18,624
Performance units – TSR						1,568						2,131												3,971						4,240
Performance units – FCF						498						—												498						—
Total share-settled awards						9,578						10,812												21,867						22,864
Cash-settled awards
Cash-settled restricted stock units						204						(130)												212						1,110
Cash-settled performance units						377						—												377						—
Total cash-settled awards						581						(130)												589						1,110
Stock-based compensation expense						$	10,159					$	10,682											$	22,456					$	23,974

12. Income Taxes

Our effective income tax rate fluctuates from the U.S. statutory tax rate based on, among other factors, changes in pretax income in jurisdictions with varying statutory tax rates, the impact of U.S. state and local taxes, the realizability of deferred tax assets and other differences related to the recognition of income and expense between GAAP and tax accounting.

Our effective income tax rate for the three months ended June 30, 2025 was (2.5)%, compared with 60.5% for the three months ended June 30, 2024. The difference in effective income tax rates between the periods was primarily attributable to the impact of valuation allowances on deferred tax assets between periods, as well as the impact of permanent differences and book impairments against earnings between periods.

Our effective income tax rate for the six months ended June 30, 2025 was (5.8)%, compared with 37.4% for the six months ended June 30, 2024. The difference in effective income tax rates between the periods was primarily attributable to the impact of valuation allowances on deferred tax assets between periods, as well as the impact of permanent differences against earnings between periods.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized, and when necessary, valuation allowances are provided. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We assess the realizability of our deferred tax assets quarterly and consider carryback availability, the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.

We continue to monitor income tax developments in the United States and other countries where we have legal entities. On July 4, 2025, the One Big Beautiful Bill Act (the “OBBBA”) was signed into law in the United States. This legislation includes several changes to existing income tax provisions with certain changes effective in 2025 and others implemented through 2027. We are currently evaluating the impact of the OBBBA on our consolidated financial statements.

13. Earnings Per Share

We provide a dual presentation of our net income (loss) per common share in our unaudited condensed consolidated statements of operations: basic net income (loss) per common share (“Basic EPS”) and diluted net income (loss) per common share (“Diluted EPS”).

Basic EPS excludes dilution and is determined by dividing the earnings attributable to common stockholders by the weighted average number of common shares outstanding during the period.

Diluted EPS is based on the weighted average number of common shares outstanding plus the dilutive effect of potential common shares, including stock options and non-vested performance units and non-vested restricted stock units. The dilutive effect of stock options, non-vested performance units and non-vested restricted stock units is determined using the treasury stock method.

19

The following table presents information necessary to calculate net income (loss) per share for the three and six months ended June 30, 2025 and 2024 as well as potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding because their inclusion would have been anti-dilutive (in thousands, except per share amounts):

			Three Months Ended June 30,												Six Months Ended June 30,
			2025						2024						2025						2024
BASIC EPS:
Net income (loss) attributable to common stockholders			$	(49,144)					$	11,077					$	(48,139)					$	62,312
Weighted average number of common shares outstanding, excluding non-vested restricted stock units			385,365						399,558						385,940						403,870
Basic net income (loss) per common share			$	(0.13)					$	0.03					$	(0.12)					$	0.15
DILUTED EPS:
Net income (loss) attributable to common stockholders			$	(49,144)					$	11,077					$	(48,139)					$	62,312
Weighted average number of common shares outstanding, including non-vested restricted stock units			385,365						399,558						385,940						403,870
Diluted net income (loss) per common share			$	(0.13)					$	0.03					$	(0.12)					$	0.15
Potentially dilutive securities excluded as anti-dilutive			10,828						8,584						10,828						8,584

14. Business Segments

Our Chief Operating Decision Maker (“CODM”) is our Chief Executive Officer, who has ultimate responsibility for enterprise decisions. Our business is organized based on the services and products we provide in three segments: (i) drilling services, (ii) completion services, and (iii) drilling products. The CODM evaluates segment performance based primarily on segment operating income (loss).

Drilling Services — represents our contract drilling, directional drilling, oilfield technology and electrical controls and automation businesses.

Completion Services — represents the combination of our well completion business, which includes hydraulic fracturing, wireline and pumping, completion support, cementing and our legacy pressure pumping business.

Drilling Products — represents our manufacturing and distribution of drill bits business.

20

The following tables summarize selected financial information relating to our business segments (in thousands):

			Drilling Services						Completion Services						Drilling Products						Total
For the three months ended June 30, 2025
Revenues from external customers			$	403,805					$	719,332					$	88,390					$	1,211,527
Direct operating costs (1)			254,772						619,083						49,335						923,190
Selling, general and administrative			4,152						9,723						8,651						22,526
Depreciation, amortization and impairment (1)			112,647						119,774						23,584						256,005
Other segment items (2)			(8,368)						—						—						(8,368)
Segment operating income (loss) (3)			$	40,602					$	(29,248)					$	6,820					$	18,174
Reconciliation of revenue:
Total segment revenues from external customers																					$	1,211,527
Other revenues (4)																					7,793
Total consolidated revenues																					$	1,219,320
Reconciliation to consolidated income (loss) before income taxes:
Segment operating income (3)																					$	18,174
Other (4)																					(2,000)
Corporate																					(45,660)
Interest income																					1,272
Interest expense																					(17,645)
Other expense																					(1,644)
Loss before income taxes																					$	(47,503)
			Drilling Services						Completion Services						Drilling Products						Total
For the three months ended June 30, 2024
Revenues from external customers			$	440,289					$	805,373					$	86,054					$	1,331,716
Direct operating costs (1)			261,497						653,240						46,147						960,884
Selling, general and administrative			4,073						10,637						8,092						22,802
Depreciation, amortization and impairment (1)			98,607						138,693						23,176						260,476
Other segment items (2)			—						(7,922)						—						(7,922)
Segment operating income (3)			$	76,112					$	10,725					$	8,639					$	95,476
Reconciliation of revenue:
Total segment revenues from external customers																					$	1,331,716
Other revenues (4)																					16,478
Total consolidated revenues																					$	1,348,194
Reconciliation to consolidated income (loss) before income taxes:
Segment operating income (3)																					$	95,476
Other (4)																					433
Corporate																					(50,681)
Interest income																					1,867
Interest expense																					(17,913)
Other income																					224
Income before income taxes																					$	29,406

(1)The significant expense categories and amounts align with the segment-level information that is regularly provided to the chief operating decision maker.

(2)Other segment items for each reportable segment includes other operating expenses (income), such as gains or losses on certain insurance recoveries or legal settlements.

(3)Segment operating income (loss) is our measure of segment profitability. It is defined as revenue less operating expenses, selling, general and administrative expenses, depreciation, amortization and impairment expense and other operating expenses (income).

(4)Other includes our oilfield rentals business, prior to its divestiture in April 2025, and oil and natural gas working interests.

21

			Drilling Services						Completion Services						Drilling Products						Total
For the six months ended June 30, 2025
Revenues from external customers			$	816,665					$	1,485,412					$	174,053					$	2,476,130
Direct operating costs (1)			502,401						1,276,764						96,275						1,875,440
Selling, general and administrative			8,097						21,132						17,770						46,999
Depreciation, amortization and impairment (1)			197,619						235,600						46,460						479,679
Other segment items (2)			(8,368)						—						—						(8,368)
Segment operating income (loss) (3)			$	116,916					$	(48,084)					$	13,548					$	82,380
Reconciliation of revenue:
Total segment revenues from external customers																					$	2,476,130
Other revenues (4)																					23,727
Total consolidated revenues																					$	2,499,857
Reconciliation to consolidated income (loss) before income taxes:
Segment operating income (3)																					$	82,380
Other (4)																					(1,770)
Corporate																					(93,151)
Interest income																					2,736
Interest expense																					(35,342)
Other income																					324
Loss before income taxes																					$	(44,823)
			Drilling Services						Completion Services						Drilling Products						Total
For the six months ended June 30, 2024
Revenues from external customers			$	897,862					$	1,750,370					$	176,027					$	2,824,259
Direct operating costs (1)			533,234						1,398,834						94,777						2,026,845
Selling, general and administrative			7,952						21,601						15,753						45,306
Depreciation, amortization and impairment (1)			190,952						287,373						50,358						528,683
Other segment items (2)			—						(17,792)						—						(17,792)
Segment operating income (3)			$	165,724					$	60,354					$	15,139					$	241,217
Reconciliation of revenue:
Total segment revenues from external customers																					$	2,824,259
Other revenues (4)																					34,295
Total consolidated revenues																					$	2,858,554
Reconciliation to consolidated income (loss) before income taxes:
Segment operating income (3)																					$	241,217
Other (4)																					1,421
Corporate																					(110,411)
Interest income																					4,056
Interest expense																					(36,248)
Other income																					1,074
Income before income taxes																					$	101,109

(1)The significant expense categories and amounts align with the segment-level information that is regularly provided to the chief operating decision maker.

(2)Other segment items for each reportable segment includes other operating expenses (income), such as gains or losses on certain insurance recoveries or legal settlements.

(3)Segment operating income (loss) is our measure of segment profitability. It is defined as revenue less operating expenses, selling, general and administrative expenses, depreciation, amortization and impairment expense and other operating expenses (income).

(4)Other includes our oilfield rentals business, prior to its divestiture in April 2025, and oil and natural gas working interests.

22

Other business segment information

			Three Months Ended June 30,												Six Months Ended June 30,
			2025						2024						2025						2024
Capital expenditures:
Drilling Services			$	55,174					$	58,426					$	128,632					$	141,219
Completion Services			68,985						48,728						131,158						172,105
Drilling Products			15,252						13,958						33,474						29,544
Segment capital expenditures			$	139,411					$	121,112					$	293,264					$	342,868
Other			1,802						9,213						5,398						13,010
Corporate			2,993						183						7,375						1,571
Total capital expenditures			$	144,206					$	130,508					$	306,037					$	357,449

			June 30, 2025						December 31, 2024
Identifiable assets:
Drilling Services			$	1,942,814					$	2,047,986
Completion Services			2,371,228						2,468,707
Drilling Products			938,676						966,200
Segment assets			$	5,252,718					$	5,482,893
Other			28,500						55,580
Corporate (1)			294,402						294,993
Total assets			$	5,575,620					$	5,833,466

(1)Corporate assets primarily include cash on hand and certain property and equipment.

15. Fair Values of Financial Instruments

The carrying values of cash, cash equivalents and restricted cash, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items. These fair value estimates are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting.

The estimated fair value of our outstanding debt balances as of June 30, 2025 and December 31, 2024 is set forth below (in thousands):

			June 30, 2025												December 31, 2024
			Carrying Value						Fair Value						Carrying Value						Fair Value
3.95% Senior Notes Due 2028			$	482,505					$	467,706					$	482,505					$	461,720
5.15% Senior Notes Due 2029			344,895						340,174						344,895						336,490
7.15% Senior Notes Due 2033			400,000						411,226						400,000						419,265
Equipment Loans Due 2025			—						—						6,395						6,424
Total debt			$	1,227,400					$	1,219,106					$	1,233,795					$	1,223,899

The fair values of the 2028 Notes, the 2029 Notes and the 2033 Notes at June 30, 2025 and December 31, 2024 are based on quoted market prices, which are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting. The fair value of the secured equipment financing term loans (“Equipment Loans”) was based on a 5.25% stated rate of interest, which was considered a Level 2 fair value estimate in the fair value hierarchy of fair value accounting. The Equipment Loans were paid off in full during the three months ended June 30, 2025.

23

The implied market rates of interest used to determine the fair value of our outstanding debt balances as of June 30, 2025 and December 31, 2024 are set forth below:

			June 30, 2025						December 31, 2024
3.95% Senior Notes Due 2028			5.24		%				5.49		%
5.15% Senior Notes Due 2029			5.51		%				5.73		%
7.15% Senior Notes Due 2033			6.70		%				6.42		%
Equipment Loans Due 2025			—		%				5.28		%

24

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Report”) and other public filings, press releases and presentations by us contain “forward-looking statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, as amended. As used in this Report, “we,” “us,” “our,” “ours” and like terms refer collectively to Patterson-UTI Energy, Inc. and its consolidated subsidiaries. Patterson-UTI Energy, Inc. conducts its operations through its wholly-owned subsidiaries and has no employees or independent business operations. These “forward-looking statements” involve risk and uncertainty. These forward-looking statements include, without limitation, statements relating to: liquidity; revenue, cost and margin expectations and backlog; financing of operations; oil and natural gas prices; rig counts and frac spreads; source and sufficiency of funds required for building new equipment, upgrading existing equipment and acquisitions (if opportunities arise); demand and pricing for our services; competition; equipment availability; government regulation; legal proceedings; debt service obligations; impact of inflation and economic downturns; and other matters. Our forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts and often use words such as “anticipate,” “believe,” “budgeted,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “pursue,” “see,” “should,” “strategy,” “target,” or “will,” or the negative thereof and other words and expressions of similar meaning. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances.

Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These risks and uncertainties also include those set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Report and other sections of our filings with the United States Securities and Exchange Commission (the “SEC”) under the Exchange Act and the Securities Act, as well as, among others, risks and uncertainties relating to:

•adverse oil and natural gas industry conditions, including the impact of commodity price volatility on industry outlook;

•global economic conditions, including inflationary pressures and risks of economic downturns or recessions in the United States and elsewhere;

•volatility in customer spending and in oil and natural gas prices that could adversely affect demand for our services and their associated effect on rates;

•excess supply of drilling and completions equipment, including as a result of reactivation, improvement or construction;

•competition and demand for our services;

•the impact of the ongoing Ukraine/Russia and Middle East conflicts and instability in other international regions;

•strength and financial resources of competitors;

•utilization, margins and planned capital expenditures;

•ability to obtain insurance coverage on commercially reasonable terms and liabilities from operational risks for which we do not have and receive full indemnification or insurance;

•operating hazards attendant to the oil and natural gas business;

•failure by customers to pay or satisfy their contractual obligations (particularly with respect to fixed-term contracts);

•the ability to realize backlog;

•specialization of methods, equipment and services and new technologies, including the ability to develop and obtain satisfactory returns from new technology and the risk of obsolescence of existing technologies;

•the ability to attract and retain management and field personnel;

•loss of key customers;

•shortages, delays in delivery, and interruptions in supply, of equipment and materials;

•cybersecurity events;

•difficulty in building and deploying new equipment;

•complications with the design or implementation of our new enterprise resource planning system;

25

•governmental regulation, including climate legislation, regulation and other related risks;

•environmental, social and governance practices, including the perception thereof;

•environmental risks and ability to satisfy future environmental costs;

•technology-related disputes;

•legal proceedings and actions by governmental or other regulatory agencies;

•changes to tax, tariff and import/export regulations and sanctions by the United States or other countries, including the impacts of any sustained escalation or changes in tariff levels or trade-related disputes;

•the ability to effectively identify and enter new markets or pursue strategic acquisitions;

•public health crises, pandemics and epidemics;

•weather;

•operating costs;

•expansion and development trends of the oil and natural gas industry;

•financial flexibility, including availability of capital and the ability to repay indebtedness when due;

•adverse credit and equity market conditions;

•our return of capital to stockholders, including timing and amounts (including any plans or commitments in respect thereof) of any dividends and share repurchases;

•stock price volatility;

•compliance with covenants under our debt agreements; and

•other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the SEC.

We caution that the foregoing list of factors is not exhaustive. Additional information concerning these and other risk factors is contained elsewhere in this Report and in our Annual Report on Form 10-K for the year ended December 31, 2024 (our “Annual Report”) and may be contained in our future filings with the SEC. You are cautioned not to place undue reliance on any of our forward-looking statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to update publicly or revise any of these forward-looking statements, whether as a result of new information, future events or otherwise. In the event that we update any forward-looking statement, no inference should be made that we will make additional updates with respect to that statement, related matters or any other forward-looking statements. All subsequent written and oral forward-looking statements concerning us or other matters and attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements above.

26

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management Overview — We are a Houston, Texas-based leading provider of drilling and completion services to oil and natural gas exploration and production companies in the United States and other select countries, including contract drilling services, integrated well completion services and directional drilling services in the United States, and specialized drill bit solutions in the United States, Middle East and many other regions around the world. We operate under three reportable business segments: (i) drilling services, (ii) completion services, and (iii) drilling products.

Drilling Services

Our contract drilling business operates in the continental United States and internationally in Colombia and Ecuador and, from time to time, we pursue contract drilling opportunities in other select markets. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and natural gas basins in the United States, and we provide services that improve the statistical accuracy of wellbore placement for directional and horizontal wells. We also service and re-certify equipment for drilling contractors, and we provide electrical controls and automation to the energy, marine and mining industries, in North America and other select markets.

As of June 30, 2025, we had 152 marketed land-based drilling rigs based in the following regions:

Region						Number of Rigs
West Texas						70
Appalachia						21
Oklahoma						16
Rockies						17
South Texas						11
East Texas						9
Colombia						7
Ecuador						1
Total						152

We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by improving the capabilities of our drilling fleet. The U.S. land rig industry has in recent years referred to certain high specification rigs as “super-spec” rigs, which we consider to be at least a 1,500 horsepower, AC-powered rig that has at least a 750,000-pound hookload, a 7,500-psi circulating system, and is pad-capable. Due to evolving customer preferences, we refer to certain premium rigs as “Tier-1, super spec” rigs, which we consider as being a super-spec rig that also has a third mud pump and raised drawworks that allows for more clearance underneath the rig floor. As of June 30, 2025, our rig fleet included 136 Tier-1, super-spec rigs.

Completion Services

Our well completion services business consists of services for hydraulic fracturing, wireline and pumping, completion support, and cementing. It also includes our power solutions natural gas fueling business and our proppant last mile logistics and storage business. Our completion services business operates in several of the most active basins in the continental United States including the Permian, the Marcellus Shale/Utica, the Eagle Ford, Mid-Continental, Haynesville, and the Bakken/Rockies.

To address evolving customer preferences for emissions-reducing equipment, we have invested in natural gas-powered equipment, including electric, direct drive, and dual fuel pumps, to replace legacy diesel completion services equipment.

Drilling Products

We serve the energy and mining markets by manufacturing and distributing drill bits throughout North America and internationally in over 30 countries. Our drilling equipment is used in oil and natural gas exploration and production and in mining operations. We have manufacturing and repair facilities located in Fort Worth, Texas, Leduc, Alberta and Saudi Arabia and repair facilities located in Argentina, Colombia and Oman.

Recent Developments in Market Conditions and Outlook — Commodity prices have historically been volatile but were relatively range-bound from the end of 2022 through the first quarter of 2025. The current demand for equipment and services remains impacted by macro conditions, including commodity prices, geopolitical environment, changes to international tariffs and

27

trade policies, inflationary pressures, economic conditions in the United States and elsewhere, as well as customer consolidation and focus by exploration and production companies and service companies on capital returns. During the second quarter of 2025, global economic conditions deteriorated, in part, because of recently enacted and proposed trade policies and tariffs by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs. Additionally, during the second quarter of 2025, OPEC+ countries began phasing out voluntary crude oil production cuts, leading to an increase in global supply. These developments, combined with rising geopolitical tensions—particularly in the Middle East—have heightened uncertainty in global energy markets, which has contributed to a decline in our share price, lowered average crude oil futures prices and increased uncertainty regarding the future economic environment in which we operate. While the full effects are yet to be determined, and commodity prices have modesty recovered from the lows in the second quarter, prolonged trade tensions and sustained lower crude oil futures prices could adversely affect our future outlook on activity and profitability. Oil prices averaged $64.57 per barrel in the second quarter of 2025, as compared to $71.78 per barrel in the first quarter of 2025, and closed at $68.39 per barrel on July 21, 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $3.19 per MMBtu in the second quarter of 2025 as compared to an average of $4.14 per MMBtu in the first quarter of 2025, and closed at $3.50 per MMBtu on July 21, 2025.

Our average active rig count in the United States for the second quarter of 2025 was 104 rigs. This was a decrease from our average active rig count for the first quarter of 2025 of 106. Term contracts help support our operating rig count. Based on contracts in place in the United States as of July 24, 2025, we expect an average of 48 rigs operating under term contracts during the third quarter of 2025 and an average of 27 rigs operating under term contracts during the four quarters ending June 30, 2026.

We maintain a backlog of commitments for contract drilling services under term contracts, which we define as contracts with a duration of six months or more. Our contract drilling backlog in the United States as of June 30, 2025 was approximately $312 million. Approximately 9% of our total contract drilling backlog in the United States at June 30, 2025 is reasonably expected to remain at June 30, 2026. See Note 2 of Notes to unaudited condensed consolidated financial statements for additional information on backlog.

In our Drilling Services segment for the third quarter of 2025, we expect our average rig count will be in the mid-90s, with the sequential change driven by moderating activity in oil basins compared to the second quarter and steady activity in natural gas basins.

In our Completion Services segment for the third quarter of 2025, we expect activity to be steady compared to the second quarter. We expect third quarter Completion Services adjusted gross profit to remain steady with the second quarter.

In our Drilling Products segment for the third quarter of 2025, we expect adjusted gross profit will improve slightly, sequentially. We expect that the Canadian market should resume normal activity following the second quarter seasonal spring breakup, and we expect slight gains in our International markets, partially offset by lower industry drilling activity in the United States.

Impact on our Business from Oil and Natural Gas Prices and Other Factors — Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas, expectations about future prices, and upon our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. During periods of improved oil and natural gas prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when oil and natural gas prices are relatively low or when our customers have a reduced ability to access, or willingness to deploy, capital, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. Even during periods of historically moderate or high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including the depletion of capital expenditure budgets and/or meeting annual drilling and completion targets, which could reduce demand for our services. We may also be impacted by delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies.

The oil and natural gas services industry is cyclical and at times experiences downturns in demand. During these periods, there has been substantially more oil and natural gas service equipment available than necessary to meet demand. As a result, oil and natural gas service contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. We cannot predict either the future level of demand for our oil and natural gas services or future conditions in the oil and natural gas service businesses.

In addition to the dependence on oil and natural gas prices and demand for our services, we are highly impacted by operational risks, competition, labor issues, weather, the availability, from time to time, of products used in our businesses, supplier delays and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see Item 1A of our Annual Report.

28

For the three months ended June 30, 2025 and March 31, 2025 and for the six months ended June 30, 2025 and June 30, 2024 our operating revenues consisted of the following (dollars in thousands):

			Three Months Ended																											Six Months Ended
			June 30,												March 31,																		June 30,												June 30,
			2025												2025																		2025												2024
Drilling Services			$	403,805					33.1		%				$	412,860					32.2		%																$	816,665					32.7		%				$	897,862					31.4		%
Completion Services			719,332						59.0		%				766,080						59.8		%																1,485,412						59.4		%				1,750,370						61.2		%
Drilling Products			88,390						7.2		%				85,663						6.7		%																174,053						7.0		%				176,027						6.2		%
Other			7,793						0.7		%				15,934						1.3		%																23,727						0.9		%				34,295						1.2		%
			$	1,219,320					100.0		%				$	1,280,537					100.0		%																$	2,499,857					100.0		%				$	2,858,554					100.0		%

Results of Operations

The following tables summarize results of operations by business segment for the three months ended June 30, 2025 and March 31, 2025:

						Three Months Ended
						June 30,						March 31,
Drilling Services						2025						2025												% Change
						(dollars in thousands)
Revenues						$	403,805					$	412,860											(2.2)		%
Direct operating costs						254,772						247,629												2.9		%
Adjusted gross profit (1)						149,033						165,231												(9.8)		%
Selling, general and administrative						4,152						3,945												5.2		%
Depreciation, amortization and impairment						112,647						84,972												32.6		%
Other operating income, net						(8,368)						—												NA
Operating income						$	40,602					$	76,314											(46.8)		%
Capital expenditures						$	55,174					$	73,458											(24.9)		%
Operating days – U.S. (2)						9,465						9,573												(1.1)		%

(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

(2)Operational data relates to our contract drilling business. A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

Generally, the revenues in our drilling services segment are most impacted by two primary factors: our contract drilling day rates and our average number of rigs operating.

Total revenues and average revenue per operating day decreased primarily due to a decrease in operating days in our contract drilling business within the United States and lower pricing. The increase in direct operating costs and average direct operating costs per operating day was primarily impacted by the fixed cost leverage for U.S. drilling rigs during the three months ended June 30, 2025.

Depreciation, amortization and impairment expense increased primarily due to a $27.8 million impairment charge to Latin American drilling equipment during the second quarter of 2025. See Note 5 of Notes to unaudited condensed consolidated financial statements for additional information.

Other operating income, net, increased due to insurance proceeds received during the second quarter of 2025.

Capital expenditures decreased primarily due to the timing of order placement and spending on committed deliveries that more heavily impacted the first quarter of 2025.

29

						Three Months Ended
						June 30,						March 31,
Completion Services						2025						2025												% Change
						(dollars in thousands)
Revenues						$	719,332					$	766,080											(6.1)		%
Direct operating costs						619,083						657,681												(5.9)		%
Adjusted gross profit (1)						100,249						108,399												(7.5)		%
Selling, general and administrative						9,723						11,409												(14.8)		%
Depreciation, amortization and impairment						119,774						115,826												3.4		%
Operating loss						$	(29,248)					$	(18,836)											55.3		%
Capital expenditures						$	68,985					$	62,173											11.0		%

(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

Completion services revenues and direct operating costs declined primarily due to a decline in activity in our fracturing and power solutions operations. Revenues from these operations collectively decreased $35 million, and direct operating costs for these operations collectively decreased by $31 million, or 5% and 6%, respectively, from the first quarter of 2025.

Selling, general and administrative expenses decreased primarily as a result of cost reduction efforts.

						Three Months Ended
						June 30,						March 31,
Drilling Products						2025						2025												% Change
						(dollars in thousands)
Revenues						$	88,390					$	85,663											3.2		%
Direct operating costs						49,335						46,940												5.1		%
Adjusted gross profit (1)						39,055						38,723												0.9		%
Selling, general and administrative						8,651						9,119												(5.1)		%
Depreciation, amortization and impairment						23,584						22,876												3.1		%
Operating income						$	6,820					$	6,728											1.4		%
Capital expenditures						$	15,252					$	18,222											(16.3)		%

(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

Revenues and direct operating costs increased primarily due to additional activity.

Direct operating costs and depreciation, amortization and impairment expense were approximately $0.5 million and $1.6 million higher than they would have otherwise been for the three months ended June 30, 2025, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting. For the three months ended March 31, 2025, direct operating costs and depreciation, amortization and impairment expense were approximately $0.6 million and $2.3 million higher than they would have otherwise been, respectively, as a result of the step up to fair value of our drill bits.

30

						Three Months Ended
						June 30,						March 31,
Other (1)						2025						2025												% Change
						(dollars in thousands)
Revenues						$	7,793					$	15,934											(51.1)		%
Direct operating costs						6,173						9,164												(32.6)		%
Adjusted gross profit (2)						1,620						6,770												(76.1)		%
Selling, general and administrative						82						204												(59.8)		%
Depreciation, depletion, amortization and impairment						3,538						6,336												(44.2)		%
Operating income (loss)						$	(2,000)					$	230											NA
Capital expenditures						$	1,802					$	3,596											(49.9)		%

(1)Other includes our oilfield rentals business, prior to its divestiture in April 2025, and oil and natural gas working interests.

(2)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

The changes for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025 can be primarily attributed to the divestiture of our oilfield rentals business during the second quarter of 2025. In order to provide a more meaningful basis for comparison, the discussion below is focused on changes between comparable periods excluding the effects of the divestiture.

Revenues and direct operating costs, excluding the effects of our oilfield rentals business divestiture, were relatively flat between sequential quarters.

Depreciation, depletion, amortization and impairment expense, excluding the effects of our oilfield rentals business divestiture, was relatively flat between sequential quarters.

						Three Months Ended
						June 30,						March 31,
Corporate						2025						2025												% Change
						(dollars in thousands)
Selling, general and administrative						$	41,500					$	42,253											(1.8)		%
Merger and integration expense						$	488					$	432											13.0		%
Depreciation						$	2,315					$	1,856											24.7		%
Other operating expense, net						$	1,357					$	2,950											(54.0)		%
Interest income						$	1,272					$	1,464											(13.1)		%
Interest expense, net of amount capitalized						$	(17,645)					$	(17,697)											(0.3)		%
Other income (expense)						$	(1,644)					$	1,968											NA
Capital expenditures						$	2,993					$	4,382											(31.7)		%

Corporate expenses were relatively flat between sequential quarters.

31

Results of Operations

The following tables summarize results of operations by business segment for the six months ended June 30, 2025 and June 30, 2024:

						Six Months Ended
						June 30,						June 30,
Drilling Services						2025						2024						% Change
						(dollars in thousands)
Revenues						$	816,665					$	897,862					(9.0)		%
Direct operating costs						502,401						533,234						(5.8)		%
Adjusted gross profit (1)						314,264						364,628						(13.8)		%
Selling, general and administrative						8,097						7,952						1.8		%
Depreciation, amortization and impairment						197,619						190,952						3.5		%
Other operating income, net						(8,368)						—						NA
Operating income						$	116,916					$	165,724					(29.5)		%
Capital expenditures						$	128,632					$	141,219					(8.9)		%
Operating days – U.S. (2)						19,038						21,412						(11.1)		%

(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

(2)Operational data relates to our contract drilling business. A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.

Total revenues and direct operating costs decreased primarily due to a decrease in operating days in our contract drilling business within the United States. However, average revenue per operating day decreased disproportionately as compared to the decrease in average direct operating costs per operating day. The decline in operating days impacted the fixed cost leverage for U.S. drilling rigs during the six months ended June 30, 2025.

The decrease in operating days for our U.S. contract drilling business reflects the industry-wide activity declines during the first six months of 2025.

Depreciation, amortization and impairment expense increased primarily due to a $27.8 million impairment charge to Latin American drilling equipment during the second quarter of 2025. This increase was partially offset by a decrease in depreciation, amortization and impairment expense which was attributable to a lower depreciable asset base in 2025, in part, due to the abandonment of 42 legacy non-super-spec rigs and equipment in the third quarter of 2024. See Note 5 of Notes to unaudited condensed consolidated financial statements and Note 6 in Notes to consolidated financial statements in Item 8 of our Annual Report for additional information.

Other operating income, net, increased due to insurance proceeds received during the second quarter of 2025.

Capital expenditures decreased primarily due to the timing of order placement as well as lower maintenance capital expenditures due to fewer operating days.

32

						Six Months Ended
						June 30,						June 30,
Completion Services						2025						2024						% Change
						(dollars in thousands)
Revenues						$	1,485,412					$	1,750,370					(15.1)		%
Direct operating costs						1,276,764						1,398,834						(8.7)		%
Adjusted gross profit (1)						208,648						351,536						(40.6)		%
Selling, general and administrative						21,132						21,601						(2.2)		%
Depreciation, amortization and impairment						235,600						287,373						(18.0)		%
Other operating income, net						—						(17,792)						(100.0)		%
Operating income (loss)						$	(48,084)					$	60,354					NA
Capital expenditures						$	131,158					$	172,105					(23.8)		%

(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

Completion services revenues and direct operating costs decreased primarily due to lower activity in our fracturing operations. Revenues and direct operating costs from our fracturing operations decreased by approximately $250 million and $123 million, or 17% and 11%, respectively.

Depreciation, amortization and impairment expense decreased primarily due to fewer capital additions placed in service relative to asset retirements between the periods.

Other operating income, net in 2024 was due to gain on legal settlements.

We reduced capital expenditures in response to changing macroeconomic conditions between the periods.

						Six Months Ended
						June 30,						June 30,
Drilling Products						2025						2024						% Change
						(dollars in thousands)
Revenues						$	174,053					$	176,027					(1.1)		%
Direct operating costs						96,275						94,777						1.6		%
Adjusted gross profit (1)						77,778						81,250						(4.3)		%
Selling, general and administrative						17,770						15,753						12.8		%
Depreciation, amortization and impairment						46,460						50,358						(7.7)		%
Operating income						$	13,548					$	15,139					(10.5)		%
Capital expenditures						$	33,474					$	29,544					13.3		%

(1)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

Revenues and direct operating costs were relatively flat between the periods.

Direct operating costs and depreciation, amortization and impairment expense were approximately $1.1 million and $3.8 million higher than they would have otherwise been for the six months ended June 30, 2025, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting. Direct operating costs and depreciation, amortization and impairment expense were approximately $3.8 million and $9.1 million higher than they would have otherwise been for the six months ended June 30, 2024, respectively, as a result of the step up to fair value of our drill bits in accordance with purchase accounting.

33

						Six Months Ended
						June 30,						June 30,
Other						2025						2024						% Change
						(dollars in thousands)
Revenues						$	23,727					$	34,295					(30.8)		%
Direct operating costs						15,337						21,458						(28.5)		%
Adjusted gross profit (1)						8,390						12,837						(34.6)		%
Selling, general and administrative						286						493						(42.0)		%
Depreciation, depletion, amortization and impairment						9,874						10,923						(9.6)		%
Operating income (loss)						$	(1,770)					$	1,421					NA
Capital expenditures						$	5,398					$	13,010					(58.5)		%

(1)Other includes our oilfield rentals business, prior to its divestiture in April 2025, and oil and natural gas working interests.

(2)Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.

The changes for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024 can be primarily attributed to the divestiture of our oilfield rentals business during the second quarter of 2025. In order to provide a more meaningful basis for comparison, the discussion below is focused on changes between comparable periods excluding the effects of the divestiture.

Excluding the effects of our oilfield rentals business divestiture, the decrease in revenue and direct operating costs was driven by lower realized crude oil prices. Oil prices averaged $68.12 per barrel in the first half of 2025 as compared to $79.69 per barrel in the first half of 2024.

Depreciation, depletion, amortization and impairment expense, excluding the effects of our oilfield rentals business divestiture, was relatively flat between the periods.

						Six Months Ended
						June 30,						June 30,
Corporate						2025						2024						% Change
						(dollars in thousands)
Selling, general and administrative						$	83,753					$	83,763					0.0		%
Merger and integration expense						$	920					$	22,878					(96.0)		%
Depreciation						$	4,171					$	2,988					39.6		%
Other operating expense, net						$	4,307					$	782					450.8		%
Interest income						$	2,736					$	4,056					(32.5)		%
Interest expense, net of amount capitalized						$	(35,342)					$	(36,248)					(2.5)		%
Other income						$	324					$	1,074					(69.8)		%
Capital expenditures						$	7,375					$	1,571					369.4		%

Merger and integration expense decreased due to the timing of the NexTier merger and the Ulterra acquisition, which both closed in the third quarter of 2023.

Interest expense was relatively flat between the periods.

The increase in capital expenditures was primarily due to the expansion of our Corporate office.

Income Taxes

Our effective income tax rate fluctuates from the U.S. statutory tax rate based on, among other factors, changes in pretax income in jurisdictions with varying statutory tax rates, the impact of U.S. state and local taxes, the realizability of deferred tax assets and other differences related to the recognition of income and expense between GAAP and tax accounting.

34

Our effective income tax rate for the three months ended June 30, 2025 was (2.5)%, compared with 51.9% for the three months ended March 31, 2025. The difference in effective income tax rates between the periods was primarily attributable to the impact of permanent differences and book impairments against earnings between periods.

Our effective income tax rate for the six months ended June 30, 2025 was (5.8)%, compared with 37.4% for the six months ended June 30, 2024. The difference in effective income tax rates between the periods was primarily attributable to the impact of valuation allowances on deferred tax assets between periods, as well as the impact of permanent differences against earnings between periods.

We continue to monitor income tax developments in the United States and other countries where we have legal entities. On July 4, 2025, the One Big Beautiful Bill Act (the “OBBBA”) was signed into law in the United States. This legislation includes several changes to existing income tax provisions with certain changes effective in 2025 and others implemented through 2027. We are currently evaluating the impact of the OBBBA on our consolidated financial statements.

Liquidity and Capital Resources

Our primary sources of liquidity are cash and cash equivalents, availability under our Credit Agreement and cash provided by operating activities. As of June 30, 2025, we had approximately $525 million in working capital, including $184 million of cash and cash equivalents, and approximately $498 million available under our Credit Agreement.

On January 31, 2025, we entered into the Second Amended and Restated Credit Agreement with the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, and the other parties thereto (the “Credit Agreement”). The Credit Agreement amended and restated our Amended and Restated Credit Agreement dated as of March 27, 2018. The commitments under the Credit Agreement are $500 million, and the loans and commitments under the Credit Agreement mature on January 31, 2030.

The Credit Agreement provides for a committed senior unsecured credit facility that permits aggregate revolving credit borrowings of up to $500 million, with a letter of credit sub-facility of $100 million and a swing line sub-facility that, at any time outstanding, is limited to the lesser of $50 million and the amount of the swing line provider’s unused commitment. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $200 million, not to exceed total commitments of $700 million.

Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate (plus a 0.10% per annum adjustment) or base rate, in each case subject to a 0% floor. The applicable margin on SOFR rate loans varies from 1.25% to 2.25% and the applicable margin on base rate loans varies from 0.25% to 1.25%, in each case determined based on our credit rating. As of June 30, 2025, the applicable margin on SOFR rate loans was 1.75% and the applicable margin on base rate loans was 0.75%. A letter of credit fee is payable by us equal to the applicable margin for SOFR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders varies from 0.15% to 0.35% based on our credit rating.

None of our subsidiaries are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt, which does not qualify for certain limited exceptions and is otherwise, in the aggregate with all other similar debt, in excess of Priority Debt (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.

The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that we believe are customary for agreements of this nature, including certain restrictions on our ability and the ability of each of our subsidiaries to grant liens and on the ability of each of our non-guarantor subsidiaries to incur debt. If our credit rating is below investment grade at both Moody’s and S&P, we will become subject to a restricted payment covenant, which would generally require us to have a Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment. Restricted payments include, among other things, dividend payments, repurchases of our common stock, distributions to holders of our common stock or any other payment or other distribution to third parties on account of our or our subsidiaries’ equity interests. Our credit rating is currently investment grade at both credit rating agencies. The Credit Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50% as of the last day of each fiscal quarter. The Credit Agreement generally defines the total debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the end of the most recently ended fiscal quarter. We were in compliance with these covenants at June 30, 2025.

35

On March 16, 2015, we entered into a Reimbursement Agreement (as amended from time to time, the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of June 30, 2025, we had $38.1 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any of our letters of credit issued thereunder. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the Prime rate plus 2.00% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts. A letter of credit fee is payable by us equal to 1.50% times the amount of outstanding letters of credit.

We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our or our subsidiaries’ property, then our reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

Pursuant to a Continuing Guaranty dated as of March 16, 2015, our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement. None of our subsidiaries are currently required to guarantee payment under the Credit Agreement.

We had $42.1 million of outstanding letters of credit at June 30, 2025, which was comprised of $38.1 million outstanding under the Reimbursement Agreement, $2.0 million outstanding under the Credit Agreement, and $2.0 million outstanding with financial institutions providing for short-term borrowing capacity, overdraft protection and bonding requirements. We maintain these letters of credit primarily for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under terms of the underlying insurance contracts and compliance with contractual obligations. These letters of credit expire annually at various times during the year and are typically renewed. As of June 30, 2025, no amounts had been drawn under the letters of credit. As of June 30, 2025, we had $37.0 million in surety bond exposure issued as financial assurance on an insurance agreement.

Our outstanding long-term debt at June 30, 2025 was $1.2 billion and consisted of $483 million of our 2028 Notes, $345 million of our 2029 Notes and $400 million of our 2033 Notes. We were in compliance with all covenants under the associated agreements and indentures at June 30, 2025.

For a full description of the Credit Agreement, the Reimbursement Agreement, the 2028 Notes, the 2029 Notes, and the 2033 Notes, see Note 8 of Notes to unaudited condensed consolidated financial statements.

Cash Requirements

We believe our current liquidity, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to maintain and make improvements to our existing equipment, service our debt, pay cash dividends and repurchase our common stock and senior notes for at least the next 12 months.

If we pursue other opportunities that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

The majority of our capital expenditures are expected to be used for normal, recurring items necessary to support our business. A portion of our capital expenditures can be adjusted and managed by us to match market demand and activity levels.

We anticipate $29.9 million of expenditures for the remainder of 2025 related to various contractual obligations such as certain commitments to purchase proppants and lease liabilities.

As of June 30, 2025, we had working capital of $525 million, including cash, cash equivalents and restricted cash of $186 million, compared to working capital of $453 million, including cash, cash equivalents and restricted cash of $241 million, at December 31, 2024.

36

During the six months ended June 30, 2025, our sources of cash flow included:

•$348 million from operating activities, and

•$28.3 million in proceeds from the disposal of property and equipment, including insurance recoveries.

During the six months ended June 30, 2025, our uses of cash flow included:

•$306 million to make capital expenditures for the betterment and refurbishment of drilling services and completion services equipment and, to a much lesser extent, equipment for our other businesses, to acquire and procure equipment to support our drilling services, completion services, drilling products, and other operations,

•$35.8 million for repurchases of our common stock,

•$61.6 million to pay dividends on our common stock,

•$6.4 million to repay the Equipment Loans;

•$4.4 million for payments related to finance leases, and

•$15.9 million for other investing and financing activities.

We paid cash dividends during the six months ended June 30, 2025 as follows:

			Per Share						Total
									(in thousands)
Paid on March 17, 2025			$	0.08					$	30,877
Paid on June 16, 2025			0.08						30,742
			$	0.16					$	61,619

On July 23, 2025, our Board of Directors approved a cash dividend on our common stock in the amount of $0.08 per share to be paid on September 15, 2025 to holders of record as of September 2, 2025. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors. Our Board of Directors may, without advance notice, reduce or suspend our dividend for any reason, including to improve our financial flexibility and position our company for long-term success. There can be no assurance that we will pay a dividend in the future.

We may, at any time and from time to time, seek to retire or purchase our outstanding debt for cash through open-market purchases, privately negotiated transactions, redemptions or otherwise. Such repurchases, if any, will be upon such terms and at such prices as we may determine, and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

In September 2013, our Board of Directors approved a stock buyback program. In February 2024, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for an aggregate of $1.0 billion of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the buyback program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. There is no expiration date associated with the buyback program. As of June 30, 2025, we had remaining authorization to purchase approximately $728 million of our outstanding common stock under the stock buyback program. Shares of stock purchased under the buyback program are held as treasury shares.

Treasury stock acquisitions during the six months ended June 30, 2025 were as follows (dollars in thousands):

			Shares						Cost
Treasury shares at beginning of period			133,440,028						$	1,951,067
Purchases pursuant to stock buyback program			4,278,723						31,434
Acquisitions pursuant to long-term incentive plans (1)			669,959						4,632
Treasury shares at end of period			138,388,710						$	1,987,133

(1)We withheld 669,959 shares during the six months ended June 30, 2025 with respect to employees’ tax withholding obligations upon the vesting of restricted stock units. These shares were acquired at fair market value. These acquisitions were made

37

pursuant to the terms of the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan, as amended and the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan, and not pursuant to the stock buyback program.

Commitments — As of June 30, 2025, we had commitments to purchase major equipment totaling approximately $94.8 million. Our completion services segment has entered into agreements to purchase minimum quantities of proppants from certain vendors. As of June 30, 2025, the remaining minimum obligation under these agreements was approximately $27.1 million, of which approximately $9.2 million, $13.1 million, and $4.8 million relate to the remainder of 2025, 2026, and 2027, respectively.

See Note 9 of Notes to unaudited condensed consolidated financial statements for additional information on our current commitments and contingencies as of June 30, 2025.

Operating lease liabilities totaled $44.7 million and finance lease liabilities totaled $21.8 million as of June 30, 2025.

Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts.

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by accounting principles generally accepted in the United States of America (“GAAP”). We define Adjusted EBITDA as net income (loss) plus income tax expense (benefit), net interest expense, depreciation, depletion, amortization and impairment expense, impairment of goodwill, and merger and integration expense. We present Adjusted EBITDA as a supplemental disclosure because we believe it provides to both management and investors additional information with respect to the performance of our fundamental business activities and a comparison of the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be construed as an alternative to the GAAP measure of net income (loss). Our computations of Adjusted EBITDA may not be the same as similarly titled measures of other companies. Set forth below is a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).

			Three Months Ended																		Six Months Ended
			June 30,						March 31,						June 30,						June 30,
			2025						2025						2024						2025						2024
			(in thousands)
Net income (loss)			$	(48,697)					$	1,290					$	11,621					$	(47,407)					$	63,327
Income tax expense			1,194						1,390						17,785						2,584						37,782
Net interest expense			16,373						16,233						16,046						32,606						32,192
Depreciation, depletion, amortization and impairment			261,858						231,866						267,638						493,724						542,594
Merger and integration expense			488						432						10,645						920						22,878
Adjusted EBITDA			$	231,216					$	251,211					$	323,735					$	482,427					$	698,773

38

Adjusted Gross Profit

We define “Adjusted gross profit” as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense). Adjusted gross profit is included as a supplemental disclosure because it is a useful indicator of our operating performance.

			Drilling Services						Completion Services						Drilling Products						Other
			(in thousands)
For the three months ended June 30, 2025
Revenues			$	403,805					$	719,332					$	88,390					$	7,793
Less direct operating costs			(254,772)						(619,083)						(49,335)						(6,173)
Less depreciation, depletion, amortization and impairment			(112,647)						(119,774)						(23,584)						(3,538)
GAAP gross profit (loss)			36,386						(19,525)						15,471						(1,918)
Depreciation, depletion, amortization and impairment			112,647						119,774						23,584						3,538
Adjusted gross profit			$	149,033					$	100,249					$	39,055					$	1,620
For the three months ended March 31, 2025
Revenues			$	412,860					$	766,080					$	85,663					$	15,934
Less direct operating costs			(247,629)						(657,681)						(46,940)						(9,164)
Less depreciation, depletion, amortization and impairment			(84,972)						(115,826)						(22,876)						(6,336)
GAAP gross profit (loss)			80,259						(7,427)						15,847						434
Depreciation, depletion, amortization and impairment			84,972						115,826						22,876						6,336
Adjusted gross profit			$	165,231					$	108,399					$	38,723					$	6,770
For the six months ended June 30, 2025
Revenues			$	816,665					$	1,485,412					$	174,053					$	23,727
Less direct operating costs			(502,401)						(1,276,764)						(96,275)						(15,337)
Less depreciation, depletion, amortization and impairment			(197,619)						(235,600)						(46,460)						(9,874)
GAAP gross profit (loss)			116,645						(26,952)						31,318						(1,484)
Depreciation, depletion, amortization and impairment			197,619						235,600						46,460						9,874
Adjusted gross profit			$	314,264					$	208,648					$	77,778					$	8,390
For the six months ended June 30, 2024
Revenues			$	897,862					$	1,750,370					$	176,027					$	34,295
Less direct operating costs			(533,234)						(1,398,834)						(94,777)						(21,458)
Less depreciation, depletion, amortization and impairment			(190,952)						(287,373)						(50,358)						(10,923)
GAAP gross profit			173,676						64,163						30,892						1,914
Depreciation, depletion, amortization and impairment			190,952						287,373						50,358						10,923
Adjusted gross profit			$	364,628					$	351,536					$	81,250					$	12,837

Critical Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates. There have been no material changes to our critical accounting estimates previously disclosed in Item 7 of our Annual Report.

Impairment of long-lived assets — We review our long-lived assets, including property and equipment and definite-lived intangible assets, for impairment whenever events or changes in circumstances indicate that the carrying amounts of certain assets may not be recovered over their estimated remaining useful lives (“triggering events”). In connection with this review, assets are

39

grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. We estimated future cash flows over the life of the respective assets or asset groupings in our assessment of its recoverability. These estimates of cash flows were based on historical trends in the industry as well as our expectations regarding the continuation of these trends in the future.

Negative market indicators such as lower industry-wide drilling rig and pressure pumping fleet count forecasts, increased volatility and margin compression for certain of our asset groups have led to our reduced outlook for activity. The reduction in activity forecasts combined with the recent decline in the market price of our common stock were considered a triggering event indicating certain of our long-lived tangible and intangible assets may be impaired. We deemed it necessary to perform recoverability tests on our hydraulic fracturing asset group within our completion services reporting unit and our Latin American contract drilling asset group during the second quarter of 2025. We estimated future cash flows over the expected remaining life of the primary asset for each asset group. On an undiscounted basis, the expected cash flows exceeded the carrying value of our hydraulic fracturing asset group within our completion services reporting unit, indicating that no impairment was required.

The recoverability test for our Latin American contract drilling asset group indicated that estimated undiscounted cash flows did not exceed its carrying value. Accordingly, we performed an impairment test and estimated the fair value of the asset group using the income approach. Under this approach, we used a discounted cash flow model, which utilized present values of cash flows to estimate fair value. Forecasted cash flows reflected known market conditions in the second quarter of 2025 and management’s anticipated business outlook for the asset group. Future cash flows were projected based on estimates of revenue, gross profit, selling, general and administrative expense, changes in working capital, and capital expenditures. Future cash flows were then discounted using a market-participant, risk-adjusted weighted average cost of capital. Based on the results of the analysis performed, we recorded a $27.8 million impairment charge to Latin American drilling equipment during the three months ended June 30, 2025 in our drilling services segment.

While the full effects of recent market developments are yet to be determined, prolonged trade tensions and sustained lower crude oil futures prices could adversely affect our future outlook on activity and profitability. If these conditions persist or deteriorate further, or if other unforeseen macroeconomic conditions emerge, they could negatively impact the expected cash flows used in our recoverability tests for our asset groups. Such changes could result in impairment charges in the future, which could be material to our results of operations and financial statements as a whole.

Goodwill — We assess goodwill at least annually on July 31, or more frequently if impairment indicators arise. Goodwill is tested at the reporting unit level, which is at or one level below our operating segments. We determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors. Any necessary goodwill impairment is determined using a quantitative impairment test. If the resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized for the amount of the shortfall. The fair value of a reporting unit is determined using significant unobservable inputs, or level 3 in the fair value hierarchy. These inputs are based on forecasts and significant judgment.

We determined our drilling products operating segment consists of a single reporting unit to which the goodwill from our 2023 acquisition of Ulterra Drilling Technologies, L.P. was allocated. We determined our completion services operating segment consisted of two reporting units; completion services, which was primarily comprised of our hydraulic fracturing operations and other integrated service offerings, and cementing services.

During the second quarter of 2025, we viewed the reduction in activity forecasts combined with the decline in the market price of our common stock as a triggering event that warranted a quantitative assessment for goodwill impairment.

We estimated the fair value of the drilling products and cementing services reporting units using the income approach. Under this approach, we used a discounted cash flow model, which utilized present values of cash flows to estimate fair value. Forecasted cash flows reflected known market conditions in the second quarter of 2025 and the expected market outlook. Future cash flows were projected based on estimates of revenue growth rates, gross profit, selling, general and administrative expense, changes in working capital, and capital expenditures. The terminal period used within the discounted cash flow model consisted of a growth estimate. Future cash flows were then discounted using a market-participant, risk-adjusted weighted average cost of capital. Financial and credit market volatility directly impacts our fair value measurement through the weighted average cost of capital used to determine a discount rate. During times of volatility, significant judgment must be applied to determine whether credit market changes are a short-term or long-term trend.

The forecast for the cementing services reporting unit assumed lower activity in 2026 compared to estimated average activity levels for full year 2025 and moderate growth estimates thereafter. Those estimates were based on future drilling rig count forecasts during the second quarter of 2025 and estimated market share. Based on the results of the goodwill impairment test, the fair value of

40

the cementing services reporting unit exceeded its carrying value with a substantial cushion. Accordingly, no impairment was recorded.

The forecast for the drilling products reporting unit assumed lower activity during 2025 relative to 2024, with growth estimates thereafter. The increases in estimated activity assumed growth in both domestic and international markets. Those growth estimates were based on drilling rig count forecasts and estimated market share. Geopolitical instability in regions in which we expect to maintain and grow market share, an unfavorable legal proceeding outcome, a global decrease in the demand of drilling products or other unforeseen macroeconomic considerations could negatively impact the key assumptions used in our goodwill assessment for our drilling products reporting unit. Based on the results of the goodwill impairment test, the fair value of the drilling products reporting unit exceeded its carrying value by approximately 8%. Accordingly, no impairment was recorded.

Assuming all changes are isolated, a decrease of 100 bps in our long-term revenue growth rate for our drilling products reporting unit would reduce our estimated fair value by approximately 7%, while a 100 bps increase to our discount rate would reduce our estimated fair value by approximately 10%.

A decrease in fair value resulting from unfavorable changes to these assumptions, or others, could result in goodwill impairment in future periods that could be material to our results of operations and financial statements as a whole.

Recently Issued Accounting Standards

See Note 1 of Notes to unaudited condensed consolidated financial statements for a discussion of the impact of recently issued accounting standards.

Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices, and upon our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. Commodity prices have historically been volatile, but were relatively range-bound from the end of 2022 through the first quarter of 2025. The current demand for equipment and services remains impacted by macro conditions, including commodity prices, geopolitical environment, changes to international tariffs and trade policies, inflationary pressures, economic conditions in the United States and elsewhere, as well as customer consolidation and focus by exploration and production companies and service companies on capital returns. During the second quarter of 2025, global economic conditions deteriorated, in part, because of recently enacted and proposed trade policies and tariffs by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs. Additionally, during the second quarter of 2025, OPEC+ countries began phasing out voluntary crude oil production cuts, leading to an increase in global supply. These developments, combined with rising geopolitical tensions—particularly in the Middle East—have heightened uncertainty in global energy markets, which has contributed to a decline in our share price, lowered average crude oil futures prices and increased uncertainty regarding the future economic environment in which we operate. While the full effects are yet to be determined, and commodity prices have modestly recovered from the lows in the second quarter, prolonged trade tensions and sustained lower crude oil futures prices could adversely affect our future outlook on activity and profitability. Oil prices averaged $64.57 per barrel in the second quarter of 2025, as compared to $71.78 per barrel in the first quarter of 2025, and closed at $68.39 per barrel on July 21, 2025. Natural gas prices (based on the Henry Hub Spot Market Price) averaged $3.19 per MMBtu in the second quarter of 2025 as compared to an average of $4.14 per MMBtu in the first quarter of 2025, and closed at $3.50 per MMBtu on July 21, 2025.

In light of these and other factors, we expect oil and natural gas prices to continue to be unpredictable and to affect our financial condition, operations and ability to access sources of capital. Higher oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future oil and natural gas prices, as well as our customers’ ability to access, and willingness to deploy, capital to fund their operating and capital expenditures. A decline in demand for oil and natural gas, prolonged low oil or natural gas prices, expectations of decreases in oil and natural gas prices or a reduction in the ability of our customers to access capital would likely result in reduced capital expenditures by our customers and decreased demand for our services, which could have a material adverse effect on our operating results, financial condition and cash flows. Even during periods of historically moderate or high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including the depletion of capital expenditure budgets and/or meeting annual drilling and completion targets, which could reduce demand for our services.

41

Impact of Inflation and Trade Policies

Moderate inflationary pressures and uncertainty regarding recently enacted and proposed changes to trade policies and tariffs by the United States and other governments, as well as uncertainty regarding potential future changes to global trade policies and tariffs, have contributed, or may contribute, to increases in the cost of certain goods, services, and labor. While the full effects are yet to be determined, prolonged trade tensions could, among other things, increase the costs of certain products used in our businesses, such as drill pipe, parts, and electronics. We continue to actively monitor market trends primarily related to sourcing of labor, supplies and equipment.

42

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

We may be exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. For quantitative and qualitative disclosures about market risk, see Part II, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in our Annual Report. There have been no material changes in our exposure to market risk.

As of June 30, 2025, we would have had exposure to interest rate market risk associated with any outstanding borrowings and letters of credit that we had under the Credit Agreement and amounts owed under the Reimbursement Agreement.

Loans under the Credit Agreement bear interest by reference, at our election, to the SOFR rate (plus a 0.10% per annum adjustment) or base rate, in each case subject to a 0% floor. The applicable margin on SOFR rate loans varies from 1.25% to 2.25% and the applicable margin on base rate loans varies from 0.25% to 1.25%, in each case determined based on our credit rating. As of June 30, 2025, the applicable margin on SOFR rate loans was 1.75% and the applicable margin on base rate loans was 0.75% A letter of credit fee is payable by us equal to the applicable margin for SOFR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders varies from 0.15% to 0.35% based on our credit rating. As of June 30, 2025, we had $2.0 million in letters of credit outstanding under the Credit Agreement and, as a result, had available borrowing capacity of approximately $498 million at that date.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any of our letters of credit issued thereunder. We are obligated to pay Scotiabank interest on all amounts not paid by us on the date of demand or when otherwise due at the Prime rate plus 2.00% per annum.

Our functional currency is primarily the U.S. dollar. Approximately 98% of our revenue during the first half of 2025 was denominated in U.S. dollars. As such, we do not believe we are significantly exposed to foreign currency exchange rate risk. However, a portion of our revenues in foreign countries are denominated in U.S. dollars, and therefore, changes in foreign currency exchange rates impact our earnings to the extent that costs associated with those U.S. dollar revenues are denominated in the local currency. Similarly, a portion of our revenues are denominated in foreign currencies, but have associated U.S. dollar costs, which also give rise to foreign currency exchange rate exposure.

The carrying values of cash, cash equivalents and restricted cash, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items.

43

ITEM 4. Controls and Procedures

Disclosure Controls and Procedures — We maintain disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act), designed to ensure that the information required to be disclosed in the reports that we file with the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10‑Q. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2025.

Changes in Internal Control Over Financial Reporting —There were no changes in our internal control over financial reporting during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act.

44

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

Certain subsidiaries we acquired in the Ulterra acquisition are defendants in a claim brought by a subsidiary of NOV Inc. alleging breach of a license agreement related to certain patents. Such subsidiaries have asserted defenses to the claim and are defending vigorously against this claim.

On February 6, 2023, Grant Prideco, Inc., ReedHycalog UK, Ltd. ReedHycalog, LP, National Oilwell Varco, LP (“NOV”) sued Ulterra Drilling Technologies, LP (“Ulterra”) and several other companies in Texas state court. NOV seeks a declaration that United States Patent No. 8,721,752 (the “’752 Patent”) is a “Licensed RH Patent” per the terms of a license agreement between Ulterra and NOV. NOV also alleges a breach of contract based on the license agreement between NOV and Ulterra and seeks allegedly owed royalties since October 22, 2021. NOV also seeks attorney’s fees.

On February 27, 2023, Ulterra filed a plea to the jurisdiction, and subject thereto, an answer, affirmative defenses and counterclaims. Ulterra’s counterclaims include: (i) declaratory judgments of non-infringement of U.S. Pat. No. 7,568,534 and the ’752 patent; (ii) a declaratory judgment of no royalties after Oct. 22, 2021; (iii) a declaratory judgment that certain other identified patents are expired and therefore not infringed after Oct. 22, 2021; and (iv) a declaratory judgment of no breach of contract. On the same day, Ulterra filed a notice of removal in federal court for the Southern District of Texas, Houston Division (SDTX 4:23-cv-00730), as well as a corresponding notice in Texas state court. NOV moved to dismiss and remand the case back to state court. On February 17, 2024, the Court denied NOV’s motion. On March 19, 2024, Ulterra moved for judgment on the pleadings regarding its declaratory judgment that certain other identified patents are expired and therefore not infringed after October 22, 2021. On February 13, 2025, the motion was granted in part and denied in part.

Discovery is closed and dispositive motions are fully briefed. Trial is currently scheduled for October 27, 2025. An unfavorable judgment or resolution of this claim not covered by indemnity could have a material impact on our financial results.

Additionally, we are party to various other legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition, cash flows or results of operations.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended June 30, 2025.

Period Covered						Total Number of Shares Purchased(1)						Average Price Paid per Share						Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs						Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs  (in thousands) (2)
April 2025						18,558						$	6.22					—						$	740,872
May 2025						2,291,007						$	6.07					2,200,000						$	727,501
June 2025						301,836						$	5.80					—						$	727,501
Total						2,611,401												2,200,000

(1)We withheld 411,401 shares during the second quarter of 2025 with respect to employees’ tax withholding obligations upon the vesting of restricted stock units. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2021 Long-Term Incentive Plan, as amended and the NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan, and not pursuant to the stock buyback program.

(2)In September 2013, our Board of Directors approved a stock buyback program. In February 2024, our Board of Directors approved an increase of the authorization under the stock buyback program to allow for an aggregate of $1.0 billion of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the buyback program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. There is no expiration date associated with the buyback program.

45

ITEM 5. Other Information

(c)During the three months ended June 30, 2025, no director or officer of the Company adopted or terminated any trading arrangements for the sale of share of our common stock.

46

ITEM 6. Exhibits

The following exhibits are filed herewith or incorporated by reference, as indicated:

3.1			Restated Certificate of Incorporation of Patterson-UTI Energy, Inc., dated as of June 6, 2024 (filed June 6, 2024 as Exhibit 4.1 to our Registration Statement on Form S-8 and incorporated herein by reference).
3.2			Amended and Restated Bylaws of Patterson-UTI Energy, Inc., effective June 14, 2023 (filed June 15, 2023 as Exhibit 3.1 to our Current Report on Form 8-K and incorporated herein by reference).
10.1*			Form of Executive Officer Restricted Stock Unit Award Agreement.+
10.2*			Form of Executive Officer Cash-Settled Restricted Stock Unit Award Agreement.+
10.3*			Form of Executive Officer Cash-Settled Performance Unit Award Agreement.+
10.4*			Form of Executive Officer Performance Unit Award Agreement (Free Cash Flow Return).+
31.1*			Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
31.2*			Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended.
32.1**			Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*			Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*			Inline XBRL Taxonomy Extension Schema Document
101.CAL*			Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*			Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*			Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*			Inline XBRL Taxonomy Extension Presentation Linkbase Document
104			The cover page from our Quarterly Report on Form 10-Q for the quarter ended June 30, 2025, has been formatted in Inline XBRL.

*			filed herewith.
**			furnished herewith.
+			management contact or compensatory plan.

47

SIGNATURE

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

			PATTERSON-UTI ENERGY, INC.
			By:			/s/ C. Andrew Smith
						C. Andrew Smith
						Executive Vice President and
						Chief Financial Officer
						(Principal Financial Officer and Duly Authorized Officer)
Date: July 29, 2025

48

FAQ

How much revenue did Patterson-UTI (PTEN) generate in Q2 2025?

PTEN reported $1.22 billion in Q2 25 revenue, down roughly 10% year-over-year.

What was PTEN’s Q2 2025 earnings per share?

Diluted EPS was -$0.13, compared with +$0.03 in Q2 2024.

How did operating cash flow change in the first half of 2025?

1H 25 operating cash flow fell to $347.9 m from $563.4 m a year earlier.

What is Patterson-UTI’s current debt profile?

Long-term debt totals $1.22 bn, primarily unsecured notes maturing 2028–2033; no borrowings on the $500 m credit facility.

Did PTEN record any impairments in Q2 2025?

Yes, the company booked a $27.8 m impairment on Latin American drilling equipment.

Is the dividend being maintained?

Yes. The Board declared a $0.08 per-share dividend payable 15 Sep 2025.