10-K 1 chk-20221231.htm 10-K chk-20221231
false00008951262022FYhttp://fasb.org/us-gaap/2022#OtherAssetsNoncurrenthttp://fasb.org/us-gaap/2022#OtherAssetsNoncurrenthttp://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrenthttp://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrenthttp://fasb.org/us-gaap/2022#OtherLiabilitieshttp://fasb.org/us-gaap/2022#OtherLiabilities00008951262022-01-012022-12-310000895126us-gaap:CommonStockMember2022-01-012022-12-310000895126chk:ClassAWarrantsMember2022-01-012022-12-310000895126chk:ClassBWarrantsMember2022-01-012022-12-310000895126chk:ClassCWarrantsMember2022-01-012022-12-3100008951262022-06-30iso4217:USD00008951262023-02-16xbrli:shares00008951262022-12-3100008951262021-12-31iso4217:USDxbrli:shares0000895126us-gaap:OilAndGasMember2022-01-012022-12-310000895126us-gaap:OilAndGasMember2021-02-102021-12-310000895126us-gaap:OilAndGasMember2021-01-012021-02-090000895126us-gaap:OilAndGasMember2020-01-012020-12-310000895126us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember2022-01-012022-12-310000895126us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember2021-02-102021-12-310000895126us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember2021-01-012021-02-090000895126us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember2020-01-012020-12-3100008951262021-02-102021-12-3100008951262021-01-012021-02-0900008951262020-01-012020-12-3100008951262021-02-0900008951262020-12-3100008951262019-12-310000895126chk:ChangeInAccruedDrillingAndCompletionCostsMember2022-01-012022-12-310000895126chk:ChangeInAccruedDrillingAndCompletionCostsMember2021-02-102021-12-310000895126chk:ChangeInAccruedDrillingAndCompletionCostsMember2021-01-012021-02-090000895126chk:ChangeInAccruedDrillingAndCompletionCostsMember2020-01-012020-12-310000895126us-gaap:PreferredStockMember2021-02-090000895126us-gaap:CommonStockMember2021-02-090000895126us-gaap:AdditionalPaidInCapitalMember2021-02-090000895126us-gaap:RetainedEarningsMember2021-02-090000895126us-gaap:AccumulatedOtherComprehensiveIncomeMember2021-02-090000895126us-gaap:TreasuryStockMember2021-02-090000895126us-gaap:NoncontrollingInterestMember2021-02-090000895126us-gaap:CommonStockMember2021-02-102021-12-310000895126us-gaap:AdditionalPaidInCapitalMember2021-02-102021-12-310000895126us-gaap:RetainedEarningsMember2021-02-102021-12-310000895126us-gaap:PreferredStockMember2021-12-310000895126us-gaap:CommonStockMember2021-12-310000895126us-gaap:AdditionalPaidInCapitalMember2021-12-310000895126us-gaap:RetainedEarningsMember2021-12-310000895126us-gaap:AccumulatedOtherComprehensiveIncomeMember2021-12-310000895126us-gaap:TreasuryStockMember2021-12-310000895126us-gaap:NoncontrollingInterestMember2021-12-310000895126us-gaap:CommonStockMember2022-01-012022-12-310000895126us-gaap:AdditionalPaidInCapitalMember2022-01-012022-12-310000895126us-gaap:RetainedEarningsMember2022-01-012022-12-310000895126us-gaap:PreferredStockMember2022-12-310000895126us-gaap:CommonStockMember2022-12-310000895126us-gaap:AdditionalPaidInCapitalMember2022-12-310000895126us-gaap:RetainedEarningsMember2022-12-310000895126us-gaap:AccumulatedOtherComprehensiveIncomeMember2022-12-310000895126us-gaap:TreasuryStockMember2022-12-310000895126us-gaap:NoncontrollingInterestMember2022-12-310000895126us-gaap:PreferredStockMember2019-12-310000895126us-gaap:CommonStockMember2019-12-310000895126us-gaap:AdditionalPaidInCapitalMember2019-12-310000895126us-gaap:RetainedEarningsMember2019-12-310000895126us-gaap:AccumulatedOtherComprehensiveIncomeMember2019-12-310000895126us-gaap:TreasuryStockMember2019-12-310000895126us-gaap:NoncontrollingInterestMember2019-12-310000895126us-gaap:CommonStockMember2020-01-012020-12-310000895126us-gaap:AdditionalPaidInCapitalMember2020-01-012020-12-310000895126us-gaap:AccumulatedOtherComprehensiveIncomeMember2020-01-012020-12-310000895126us-gaap:RetainedEarningsMember2020-01-012020-12-310000895126chk:PreferredStockExchangedforSharesofCommonStockMemberus-gaap:PreferredStockMember2020-01-012020-12-310000895126us-gaap:CommonStockMemberchk:PreferredStockExchangedforSharesofCommonStockMember2020-01-012020-12-310000895126chk:PreferredStockExchangedforSharesofCommonStockMember2020-01-012020-12-310000895126us-gaap:TreasuryStockMember2020-01-012020-12-310000895126us-gaap:NoncontrollingInterestMember2020-01-012020-12-310000895126us-gaap:PreferredStockMember2020-12-310000895126us-gaap:CommonStockMember2020-12-310000895126us-gaap:AdditionalPaidInCapitalMember2020-12-310000895126us-gaap:RetainedEarningsMember2020-12-310000895126us-gaap:AccumulatedOtherComprehensiveIncomeMember2020-12-310000895126us-gaap:TreasuryStockMember2020-12-310000895126us-gaap:NoncontrollingInterestMember2020-12-310000895126us-gaap:CommonStockMember2021-01-012021-02-090000895126us-gaap:AdditionalPaidInCapitalMember2021-01-012021-02-090000895126us-gaap:AccumulatedOtherComprehensiveIncomeMember2021-01-012021-02-090000895126us-gaap:RetainedEarningsMember2021-01-012021-02-090000895126us-gaap:PreferredStockMember2021-01-012021-02-090000895126us-gaap:AdditionalPaidInCapitalMemberchk:ClassAWarrantsMember2021-01-012021-02-090000895126chk:ClassAWarrantsMember2021-01-012021-02-090000895126us-gaap:AdditionalPaidInCapitalMemberchk:ClassBWarrantsMember2021-01-012021-02-090000895126chk:ClassBWarrantsMember2021-01-012021-02-090000895126us-gaap:AdditionalPaidInCapitalMemberchk:ClassCWarrantsMember2021-01-012021-02-090000895126chk:ClassCWarrantsMember2021-01-012021-02-09chk:segment0000895126us-gaap:LineOfCreditMember2022-12-310000895126chk:ExitCreditFacilityMemberus-gaap:LineOfCreditMember2022-01-012022-12-310000895126us-gaap:SeniorNotesMember2022-12-310000895126chk:EmployeeMember2022-01-012022-12-310000895126chk:NewCommonStockMember2021-02-092021-02-090000895126chk:NewCommonStockMember2021-02-090000895126chk:NewCommonStockMemberchk:UponExerciseOfWarrantsMember2021-02-090000895126chk:NewCommonStockMemberchk:FLLOTermLoanFacilityMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:SecondLienNotesMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:SecondLienNotesMemberchk:ClassAWarrantsMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:SecondLienNotesMemberchk:ClassAWarrantsMember2021-02-090000895126chk:NewCommonStockMemberchk:SecondLienNotesMemberchk:ClassBWarrantsMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:SecondLienNotesMemberchk:ClassBWarrantsMember2021-02-090000895126chk:NewCommonStockMemberchk:ClassCWarrantsMemberchk:SecondLienNotesMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:ClassCWarrantsMemberchk:SecondLienNotesMember2021-02-090000895126chk:NewCommonStockMemberchk:AllowedUnsecuredNotesMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:AllowedUnsecuredNotesMemberchk:ClassCWarrantsMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:AllowedUnsecuredNotesMemberchk:ClassCWarrantsMember2021-02-090000895126chk:NewCommonStockMemberchk:AllowedGeneralUnsecuredClaimMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:ClassCWarrantsMemberchk:AllowedGeneralUnsecuredClaimMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:ClassCWarrantsMemberchk:AllowedGeneralUnsecuredClaimMember2021-02-090000895126chk:AllowedGeneralUnsecuredClaimMember2021-02-092021-02-090000895126srt:MaximumMemberchk:AllowedGeneralUnsecuredClaimMember2021-02-092021-02-09xbrli:pure0000895126chk:NewCommonStockMemberchk:RightsOfferingMember2021-02-092021-02-090000895126chk:BackstopPartiesPutOptionPremiumMemberchk:NewCommonStockMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:BackstopPartiesObligationsMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:ClassCWarrantsMember2021-02-090000895126chk:A2021LongTermIncentivePlanMember2021-02-090000895126srt:DirectorMember2021-02-09chk:boardMember0000895126chk:NonEmployeeDirectorsMember2021-02-090000895126srt:MaximumMember2021-02-090000895126us-gaap:ReorganizationChapter11PredecessorBeforeAdjustmentMember2021-02-090000895126srt:MinimumMemberus-gaap:ReorganizationChapter11FreshStartAdjustmentMember2021-02-090000895126srt:MaximumMemberus-gaap:ReorganizationChapter11FreshStartAdjustmentMember2021-02-090000895126us-gaap:ReorganizationChapter11FreshStartAdjustmentMember2021-02-090000895126chk:FivePointFivePercentSeniorNotesDue2026Memberus-gaap:SeniorNotesMember2021-02-090000895126us-gaap:SeniorNotesMemberchk:FivePointEightSevenFivePercentSeniorNotesDue2029Member2021-02-090000895126chk:ClassAWarrantsMember2021-02-090000895126chk:ClassBWarrantsMember2021-02-090000895126chk:ClassCWarrantsMember2021-02-090000895126us-gaap:ReorganizationChapter11PlanEffectAdjustmentMember2021-02-090000895126us-gaap:ReorganizationChapter11PlanEffectAdjustmentMember2021-02-092021-02-090000895126chk:DIPFacilityMember2021-02-092021-02-090000895126chk:TrancheAAndTrancheBLoansMemberus-gaap:SecuredDebtMember2021-02-090000895126us-gaap:ReorganizationChapter11PredecessorBeforeAdjustmentMember2021-02-092021-02-090000895126us-gaap:ReorganizationChapter11PredecessorBeforeAdjustmentMemberchk:ClassAWarrantsMember2021-02-092021-02-090000895126us-gaap:ReorganizationChapter11PredecessorBeforeAdjustmentMemberchk:ClassBWarrantsMember2021-02-092021-02-090000895126chk:ClassCWarrantsMemberus-gaap:ReorganizationChapter11PredecessorBeforeAdjustmentMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:ClassAWarrantsMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:ClassBWarrantsMember2021-02-092021-02-090000895126chk:NewCommonStockMemberchk:ClassCWarrantsMember2021-02-092021-02-0900008951262021-02-092021-02-090000895126chk:ClassAWarrantsMember2021-02-092021-02-090000895126chk:ClassBWarrantsMember2021-02-092021-02-090000895126chk:ClassCWarrantsMember2021-02-092021-02-090000895126us-gaap:ReorganizationChapter11PlanEffectAdjustmentMember2021-01-012021-02-090000895126us-gaap:ReorganizationChapter11PlanEffectAdjustmentMember2020-01-012020-12-310000895126chk:MarcellusMember2022-03-092022-03-090000895126chk:ExitCreditFacilityMemberchk:MarcellusMember2022-03-090000895126chk:MarcellusMember2022-03-090000895126us-gaap:OilAndGasMemberchk:MarcellusMember2022-03-102022-12-310000895126us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMemberchk:MarcellusMember2022-03-102022-12-310000895126chk:MarcellusMember2022-03-102022-12-310000895126chk:VineEnergyCorporationVineMember2021-11-012021-11-010000895126chk:VineEnergyCorporationVineMemberchk:NewRBLMember2021-11-010000895126chk:SixPointSevenFivePercentSeniorNotesMemberus-gaap:SeniorNotesMember2021-11-010000895126chk:SixPointSevenFivePercentSeniorNotesMemberus-gaap:SeniorNotesMember2021-11-012021-11-010000895126chk:VineEnergyCorporationVineMember2021-11-010000895126chk:VineEnergyCorporationVineMember2021-11-012021-12-310000895126chk:VineEnergyCorporationVineMember2022-01-012022-12-310000895126us-gaap:DisposalGroupDisposedOfBySaleNotDiscontinuedOperationsMember2022-03-252022-03-250000895126us-gaap:DisposalGroupDisposedOfBySaleNotDiscontinuedOperationsMember2022-01-012022-12-310000895126us-gaap:DisposalGroupDisposedOfBySaleNotDiscontinuedOperationsMember2022-04-012022-12-310000895126us-gaap:DisposalGroupDisposedOfBySaleNotDiscontinuedOperationsMember2020-12-112020-12-110000895126chk:MidContinentMember2020-12-112020-12-1100008951262020-12-15chk:wellutr:acre00008951262020-12-152020-12-150000895126chk:ClassCWarrantsMember2021-02-102021-12-310000895126chk:FivePointFivePercentSeniorNotesDue2026Memberus-gaap:SeniorNotesMember2022-12-310000895126chk:NewCreditFacilityMemberus-gaap:LineOfCreditMember2022-12-310000895126chk:NewCreditFacilityMemberus-gaap:LineOfCreditMember2021-12-310000895126chk:ExitCreditFacilityTrancheALoansMemberus-gaap:LineOfCreditMember2022-12-310000895126chk:ExitCreditFacilityTrancheALoansMemberus-gaap:LineOfCreditMember2021-12-310000895126chk:ExitCreditFacilityTrancheBLoansMemberus-gaap:LineOfCreditMember2022-12-310000895126chk:ExitCreditFacilityTrancheBLoansMemberus-gaap:LineOfCreditMember2021-12-310000895126chk:FivePointFivePercentSeniorNotesDue2026Memberus-gaap:SeniorNotesMember2021-12-310000895126us-gaap:SeniorNotesMemberchk:FivePointEightSevenFivePercentSeniorNotesDue2029Member2022-12-310000895126us-gaap:SeniorNotesMemberchk:FivePointEightSevenFivePercentSeniorNotesDue2029Member2021-12-310000895126chk:SixPointSevenFiveSeniorNotesDue2029Memberus-gaap:SeniorNotesMember2022-12-310000895126chk:SixPointSevenFiveSeniorNotesDue2029Memberus-gaap:SeniorNotesMember2021-12-310000895126us-gaap:SeniorNotesMember2021-12-310000895126us-gaap:LineOfCreditMemberchk:NewCreditFacilityMember2022-12-310000895126us-gaap:LetterOfCreditMemberus-gaap:LineOfCreditMemberchk:NewCreditFacilityMember2022-12-310000895126chk:SwinglineLoansMemberus-gaap:LineOfCreditMemberchk:NewCreditFacilityMember2022-12-310000895126srt:MinimumMemberus-gaap:LineOfCreditMemberchk:NewCreditFacilityMember2022-12-310000895126srt:MaximumMemberus-gaap:LineOfCreditMemberchk:NewCreditFacilityMember2022-12-310000895126srt:MinimumMemberus-gaap:LineOfCreditMemberchk:NewCreditFacilityMember2022-12-012022-12-310000895126srt:MaximumMemberus-gaap:LineOfCreditMemberchk:NewCreditFacilityMember2022-12-012022-12-310000895126us-gaap:LineOfCreditMemberchk:NewCreditFacilityMember2022-12-012022-12-310000895126chk:FederalFundsEffectiveRateMemberus-gaap:LineOfCreditMemberchk:NewCreditFacilityMember2022-12-012022-12-310000895126chk:SOFROneMonthPeriodMemberus-gaap:LineOfCreditMemberchk:NewCreditFacilityMember2022-12-012022-12-310000895126srt:MinimumMemberus-gaap:LineOfCreditMemberchk:NewCreditFacilityMemberchk:SOFROneMonthPeriodAdditionalApplicableMarginMember2022-12-012022-12-310000895126srt:MaximumMemberus-gaap:LineOfCreditMemberchk:NewCreditFacilityMemberchk:SOFROneMonthPeriodAdditionalApplicableMarginMember2022-12-012022-12-310000895126chk:ExitCreditFacilityMemberus-gaap:LineOfCreditMember2021-02-090000895126us-gaap:LineOfCreditMemberchk:ExitCreditFacilityTrancheALoansMember2021-02-090000895126us-gaap:LineOfCreditMemberchk:ExitCreditFacilityTrancheBLoansMember2021-02-090000895126us-gaap:LetterOfCreditMemberchk:ExitCreditFacilityMemberus-gaap:LineOfCreditMember2021-02-090000895126srt:MinimumMemberchk:ExitCreditFacilityMemberus-gaap:LineOfCreditMemberus-gaap:BaseRateMember2021-02-092021-02-090000895126srt:MaximumMemberchk:ExitCreditFacilityMemberus-gaap:LineOfCreditMemberus-gaap:BaseRateMember2021-02-092021-02-090000895126us-gaap:LondonInterbankOfferedRateLIBORMembersrt:MinimumMemberchk:ExitCreditFacilityMemberus-gaap:LineOfCreditMember2021-02-092021-02-090000895126srt:MaximumMemberus-gaap:LondonInterbankOfferedRateLIBORMemberchk:ExitCreditFacilityMemberus-gaap:LineOfCreditMember2021-02-092021-02-090000895126chk:ExitCreditFacilityMemberus-gaap:LineOfCreditMember2021-02-092021-02-090000895126us-gaap:LineOfCreditMember2022-01-012022-12-310000895126chk:SecuredDebtOtherMember2022-12-310000895126us-gaap:SeniorNotesMember2021-02-090000895126chk:SixPointSevenFivePercentSeniorNotesMemberus-gaap:SeniorNotesMember2022-12-310000895126chk:SixPointSevenFivePercentSeniorNotesMemberus-gaap:SeniorNotesMember2021-04-070000895126chk:GatheringProcessingandTransportationAgreementMember2022-12-310000895126srt:MinimumMember2022-12-310000895126srt:MaximumMember2022-12-310000895126chk:NaturalGasSalesMemberchk:MarcellusMember2022-01-012022-12-310000895126chk:OilSalesMemberchk:MarcellusMember2022-01-012022-12-310000895126chk:NaturalGasLiquidsSalesMemberchk:MarcellusMember2022-01-012022-12-310000895126us-gaap:OilAndGasMemberchk:MarcellusMember2022-01-012022-12-310000895126chk:NaturalGasSalesMemberchk:HaynesvilleMember2022-01-012022-12-310000895126chk:OilSalesMemberchk:HaynesvilleMember2022-01-012022-12-310000895126chk:NaturalGasLiquidsSalesMemberchk:HaynesvilleMember2022-01-012022-12-310000895126us-gaap:OilAndGasMemberchk:HaynesvilleMember2022-01-012022-12-310000895126chk:NaturalGasSalesMemberchk:EagleFordMember2022-01-012022-12-310000895126chk:OilSalesMemberchk:EagleFordMember2022-01-012022-12-310000895126chk:NaturalGasLiquidsSalesMemberchk:EagleFordMember2022-01-012022-12-310000895126us-gaap:OilAndGasMemberchk:EagleFordMember2022-01-012022-12-310000895126chk:PowderRiverBasinMemberchk:NaturalGasSalesMember2022-01-012022-12-310000895126chk:PowderRiverBasinMemberchk:OilSalesMember2022-01-012022-12-310000895126chk:PowderRiverBasinMemberchk:NaturalGasLiquidsSalesMember2022-01-012022-12-310000895126chk:PowderRiverBasinMemberus-gaap:OilAndGasMember2022-01-012022-12-310000895126chk:NaturalGasSalesMember2022-01-012022-12-310000895126chk:OilSalesMember2022-01-012022-12-310000895126chk:NaturalGasLiquidsSalesMember2022-01-012022-12-310000895126chk:NaturalGasMarketingSalesMember2022-01-012022-12-310000895126chk:OilMarketingSalesMember2022-01-012022-12-310000895126chk:NaturalGasLiquidsMarketingSalesMember2022-01-012022-12-310000895126chk:NaturalGasSalesMemberchk:MarcellusMember2021-02-102021-12-310000895126chk:OilSalesMemberchk:MarcellusMember2021-02-102021-12-310000895126chk:NaturalGasLiquidsSalesMemberchk:MarcellusMember2021-02-102021-12-310000895126us-gaap:OilAndGasMemberchk:MarcellusMember2021-02-102021-12-310000895126chk:NaturalGasSalesMemberchk:HaynesvilleMember2021-02-102021-12-310000895126chk:OilSalesMemberchk:HaynesvilleMember2021-02-102021-12-310000895126chk:NaturalGasLiquidsSalesMemberchk:HaynesvilleMember2021-02-102021-12-310000895126us-gaap:OilAndGasMemberchk:HaynesvilleMember2021-02-102021-12-310000895126chk:NaturalGasSalesMemberchk:EagleFordMember2021-02-102021-12-310000895126chk:OilSalesMemberchk:EagleFordMember2021-02-102021-12-310000895126chk:NaturalGasLiquidsSalesMemberchk:EagleFordMember2021-02-102021-12-310000895126us-gaap:OilAndGasMemberchk:EagleFordMember2021-02-102021-12-310000895126chk:PowderRiverBasinMemberchk:NaturalGasSalesMember2021-02-102021-12-310000895126chk:PowderRiverBasinMemberchk:OilSalesMember2021-02-102021-12-310000895126chk:PowderRiverBasinMemberchk:NaturalGasLiquidsSalesMember2021-02-102021-12-310000895126chk:PowderRiverBasinMemberus-gaap:OilAndGasMember2021-02-102021-12-310000895126chk:NaturalGasSalesMember2021-02-102021-12-310000895126chk:OilSalesMember2021-02-102021-12-310000895126chk:NaturalGasLiquidsSalesMember2021-02-102021-12-310000895126chk:NaturalGasMarketingSalesMember2021-02-102021-12-310000895126chk:OilMarketingSalesMember2021-02-102021-12-310000895126chk:NaturalGasLiquidsMarketingSalesMember2021-02-102021-12-310000895126chk:NaturalGasSalesMemberchk:MarcellusMember2021-01-012021-02-090000895126chk:OilSalesMemberchk:MarcellusMember2021-01-012021-02-090000895126chk:NaturalGasLiquidsSalesMemberchk:MarcellusMember2021-01-012021-02-090000895126us-gaap:OilAndGasMemberchk:MarcellusMember2021-01-012021-02-090000895126chk:NaturalGasSalesMemberchk:HaynesvilleMember2021-01-012021-02-090000895126chk:OilSalesMemberchk:HaynesvilleMember2021-01-012021-02-090000895126chk:NaturalGasLiquidsSalesMemberchk:HaynesvilleMember2021-01-012021-02-090000895126us-gaap:OilAndGasMemberchk:HaynesvilleMember2021-01-012021-02-090000895126chk:NaturalGasSalesMemberchk:EagleFordMember2021-01-012021-02-090000895126chk:OilSalesMemberchk:EagleFordMember2021-01-012021-02-090000895126chk:NaturalGasLiquidsSalesMemberchk:EagleFordMember2021-01-012021-02-090000895126us-gaap:OilAndGasMemberchk:EagleFordMember2021-01-012021-02-090000895126chk:PowderRiverBasinMemberchk:NaturalGasSalesMember2021-01-012021-02-090000895126chk:PowderRiverBasinMemberchk:OilSalesMember2021-01-012021-02-090000895126chk:PowderRiverBasinMemberchk:NaturalGasLiquidsSalesMember2021-01-012021-02-090000895126chk:PowderRiverBasinMemberus-gaap:OilAndGasMember2021-01-012021-02-090000895126chk:NaturalGasSalesMember2021-01-012021-02-090000895126chk:OilSalesMember2021-01-012021-02-090000895126chk:NaturalGasLiquidsSalesMember2021-01-012021-02-090000895126chk:NaturalGasMarketingSalesMember2021-01-012021-02-090000895126chk:OilMarketingSalesMember2021-01-012021-02-090000895126chk:NaturalGasLiquidsMarketingSalesMember2021-01-012021-02-090000895126chk:NaturalGasSalesMemberchk:MarcellusMember2020-01-012020-12-310000895126chk:OilSalesMemberchk:MarcellusMember2020-01-012020-12-310000895126chk:NaturalGasLiquidsSalesMemberchk:MarcellusMember2020-01-012020-12-310000895126us-gaap:OilAndGasMemberchk:MarcellusMember2020-01-012020-12-310000895126chk:NaturalGasSalesMemberchk:HaynesvilleMember2020-01-012020-12-310000895126chk:OilSalesMemberchk:HaynesvilleMember2020-01-012020-12-310000895126chk:NaturalGasLiquidsSalesMemberchk:HaynesvilleMember2020-01-012020-12-310000895126us-gaap:OilAndGasMemberchk:HaynesvilleMember2020-01-012020-12-310000895126chk:NaturalGasSalesMemberchk:EagleFordMember2020-01-012020-12-310000895126chk:OilSalesMemberchk:EagleFordMember2020-01-012020-12-310000895126chk:NaturalGasLiquidsSalesMemberchk:EagleFordMember2020-01-012020-12-310000895126us-gaap:OilAndGasMemberchk:EagleFordMember2020-01-012020-12-310000895126chk:PowderRiverBasinMemberchk:NaturalGasSalesMember2020-01-012020-12-310000895126chk:PowderRiverBasinMemberchk:OilSalesMember2020-01-012020-12-310000895126chk:PowderRiverBasinMemberchk:NaturalGasLiquidsSalesMember2020-01-012020-12-310000895126chk:PowderRiverBasinMemberus-gaap:OilAndGasMember2020-01-012020-12-310000895126chk:NaturalGasSalesMemberchk:MidContinentMember2020-01-012020-12-310000895126chk:OilSalesMemberchk:MidContinentMember2020-01-012020-12-310000895126chk:NaturalGasLiquidsSalesMemberchk:MidContinentMember2020-01-012020-12-310000895126us-gaap:OilAndGasMemberchk:MidContinentMember2020-01-012020-12-310000895126chk:NaturalGasSalesMember2020-01-012020-12-310000895126chk:OilSalesMember2020-01-012020-12-310000895126chk:NaturalGasLiquidsSalesMember2020-01-012020-12-310000895126chk:NaturalGasMarketingSalesMemberchk:MarketingRevenueFromContractsWithCustomersMember2020-01-012020-12-310000895126chk:OilMarketingSalesMemberchk:MarketingRevenueFromContractsWithCustomersMember2020-01-012020-12-310000895126chk:NaturalGasLiquidsMarketingSalesMemberchk:MarketingRevenueFromContractsWithCustomersMember2020-01-012020-12-310000895126us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMemberchk:MarketingRevenueFromContractsWithCustomersMember2020-01-012020-12-310000895126chk:OtherMarketingRevenueMemberchk:NaturalGasMarketingSalesMember2020-01-012020-12-310000895126chk:OtherMarketingRevenueMemberchk:OilMarketingSalesMember2020-01-012020-12-310000895126chk:NaturalGasLiquidsMarketingSalesMemberchk:OtherMarketingRevenueMember2020-01-012020-12-310000895126chk:OtherMarketingRevenueMemberus-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember2020-01-012020-12-310000895126chk:NaturalGasMarketingSalesMember2020-01-012020-12-310000895126chk:OilMarketingSalesMember2020-01-012020-12-310000895126chk:NaturalGasLiquidsMarketingSalesMember2020-01-012020-12-310000895126us-gaap:SalesRevenueNetMemberchk:ShellEnergyNorthAmericaMemberus-gaap:CustomerConcentrationRiskMember2022-01-012022-12-310000895126us-gaap:SalesRevenueNetMemberchk:ValeroEnergyCorporationMemberus-gaap:CustomerConcentrationRiskMember2022-01-012022-12-310000895126us-gaap:SalesRevenueNetMemberchk:ValeroEnergyCorporationMemberus-gaap:CustomerConcentrationRiskMember2021-02-102021-12-310000895126us-gaap:SalesRevenueNetMemberus-gaap:CustomerConcentrationRiskMemberchk:EnergyTransferCrudeMarketingMember2021-02-102021-12-310000895126us-gaap:SalesRevenueNetMemberchk:ValeroEnergyCorporationMemberus-gaap:CustomerConcentrationRiskMember2021-01-012021-02-090000895126us-gaap:SalesRevenueNetMemberchk:ValeroEnergyCorporationMemberus-gaap:CustomerConcentrationRiskMember2020-01-012020-12-310000895126chk:NaturalGasOilAndNGLSalesMember2022-12-310000895126chk:NaturalGasOilAndNGLSalesMember2021-12-310000895126chk:JointInterestMember2022-12-310000895126chk:JointInterestMember2021-12-310000895126chk:OtherRevenueMember2022-12-310000895126chk:OtherRevenueMember2021-12-3100008951262022-10-012022-12-3100008951262020-01-012020-03-310000895126chk:VineEnergyCorporationVineMember2021-12-310000895126chk:VineEnergyCorporationVineMember2022-12-310000895126chk:AttributesSubjectToSection382BaseAnnualLimitation54MillionMemberchk:A2037Memberus-gaap:DomesticCountryMember2022-12-310000895126chk:A2037Memberus-gaap:DomesticCountryMemberchk:AttributesSubjectToSection382BaseAnnualLimitation2MillionMember2022-12-310000895126chk:AttributesNotSubjectToSection382LimitationMemberchk:A2037Memberus-gaap:DomesticCountryMember2022-12-310000895126chk:AttributesSubjectToSection382BaseAnnualLimitation54MillionMemberus-gaap:DomesticCountryMember2022-12-310000895126us-gaap:DomesticCountryMemberchk:AttributesSubjectToSection382BaseAnnualLimitation2MillionMember2022-12-310000895126chk:AttributesNotSubjectToSection382LimitationMemberus-gaap:DomesticCountryMember2022-12-310000895126chk:AttributesSubjectToSection382BaseAnnualLimitation54MillionMemberus-gaap:GeneralBusinessMember2022-12-310000895126us-gaap:GeneralBusinessMemberchk:AttributesSubjectToSection382BaseAnnualLimitation2MillionMember2022-12-310000895126chk:AttributesNotSubjectToSection382LimitationMemberus-gaap:GeneralBusinessMember2022-12-310000895126us-gaap:StateAndLocalJurisdictionMember2022-12-310000895126us-gaap:StateAndLocalJurisdictionMember2021-12-310000895126stpr:PAus-gaap:StateAndLocalJurisdictionMember2022-12-310000895126chk:NewCommonStockMember2022-12-310000895126chk:NewCommonStockMember2021-12-310000895126chk:NewCommonStockMemberchk:VineEnergyCorporationVineMember2021-11-012021-11-010000895126chk:NewCommonStockMemberchk:MarcellusMember2022-03-092022-03-0900008951262021-06-102021-06-1000008951262021-09-092021-09-0900008951262021-12-092021-12-0900008951262022-03-222022-03-2200008951262022-06-022022-06-0200008951262022-09-012022-09-0100008951262022-12-012022-12-010000895126us-gaap:SubsequentEventMember2023-02-2100008951262021-12-020000895126chk:ClassAWarrantsMember2021-02-102021-12-310000895126chk:ClassBWarrantsMember2021-02-102021-12-310000895126chk:ClassCWarrantsMember2021-02-102021-12-310000895126chk:ClassAWarrantsMember2021-12-310000895126chk:ClassBWarrantsMember2021-12-310000895126chk:ClassCWarrantsMember2021-12-310000895126chk:ClassAWarrantsMember2022-01-012022-12-310000895126chk:ClassBWarrantsMember2022-01-012022-12-310000895126chk:ClassCWarrantsMember2022-01-012022-12-310000895126chk:ClassAWarrantsMember2022-12-310000895126chk:ClassBWarrantsMember2022-12-310000895126chk:ClassCWarrantsMember2022-12-310000895126us-gaap:WarrantMember2022-01-012022-12-310000895126chk:NewCommonStockMember2022-10-072022-10-130000895126chk:ClassAWarrantsMember2022-10-072022-10-130000895126chk:ClassBWarrantsMember2022-10-072022-10-130000895126chk:ClassCWarrantsMember2022-10-072022-10-130000895126chk:ClassAWarrantsMember2022-10-130000895126chk:ClassBWarrantsMember2022-10-130000895126chk:ClassCWarrantsMember2022-10-130000895126chk:NoncontrollingInterestChesapeakeGraniteWashTrustMember2020-12-310000895126chk:NoncontrollingInterestChesapeakeGraniteWashTrustMember2020-01-012020-12-310000895126srt:MinimumMemberus-gaap:RestrictedStockMemberchk:EmployeesMember2021-02-102021-12-310000895126srt:MinimumMemberus-gaap:RestrictedStockMemberchk:EmployeesMember2022-01-012022-12-310000895126srt:MaximumMemberus-gaap:RestrictedStockMemberchk:EmployeesMember2022-01-012022-12-310000895126srt:DirectorMemberus-gaap:RestrictedStockMember2021-02-102021-12-310000895126srt:DirectorMemberus-gaap:RestrictedStockMember2022-01-012022-12-310000895126us-gaap:RestrictedStockMember2021-02-090000895126us-gaap:RestrictedStockMember2021-02-102021-12-310000895126us-gaap:RestrictedStockMember2021-12-310000895126us-gaap:RestrictedStockMember2022-01-012022-12-310000895126us-gaap:RestrictedStockMember2022-12-310000895126chk:VineEnergyCorporationVineMemberus-gaap:RestrictedStockMember2021-02-102021-12-310000895126us-gaap:RestrictedStockUnitsRSUMember2022-01-012022-12-310000895126us-gaap:RestrictedStockUnitsRSUMember2021-02-102021-12-310000895126us-gaap:RestrictedStockUnitsRSUMember2022-12-310000895126us-gaap:PerformanceSharesMembersrt:ManagementMember2021-02-102021-12-310000895126us-gaap:PerformanceSharesMembersrt:ManagementMember2022-01-012022-12-310000895126us-gaap:PerformanceSharesMembersrt:MinimumMember2022-01-012022-12-310000895126us-gaap:PerformanceSharesMembersrt:MinimumMember2021-02-102021-12-310000895126srt:MaximumMemberus-gaap:PerformanceSharesMember2021-02-102021-12-310000895126srt:MaximumMemberus-gaap:PerformanceSharesMember2022-01-012022-12-310000895126chk:TotalShareholderReturnTSRAndRelativeTSRRTSRMemberus-gaap:PerformanceSharesMember2022-01-012022-12-310000895126chk:TotalShareholderReturnTSRAndRelativeTSRRTSRMemberus-gaap:PerformanceSharesMember2021-02-102021-12-310000895126us-gaap:PerformanceSharesMemberchk:SharePriceHurdleMember2021-02-102021-12-310000895126us-gaap:PerformanceSharesMember2021-02-090000895126us-gaap:PerformanceSharesMember2021-02-102021-12-310000895126us-gaap:PerformanceSharesMember2021-12-310000895126us-gaap:PerformanceSharesMember2022-01-012022-12-310000895126us-gaap:PerformanceSharesMember2022-12-310000895126us-gaap:RestrictedStockMember2020-12-310000895126us-gaap:RestrictedStockMember2021-01-012021-02-090000895126us-gaap:RestrictedStockMember2019-12-310000895126us-gaap:RestrictedStockMember2020-01-012020-12-310000895126us-gaap:RestrictedStockUnitsRSUMember2020-01-012020-12-310000895126us-gaap:EmployeeStockOptionMember2020-01-012020-12-310000895126us-gaap:EmployeeStockOptionMembersrt:MinimumMembersrt:ManagementMember2020-01-012020-12-310000895126srt:MaximumMemberus-gaap:EmployeeStockOptionMembersrt:ManagementMember2020-01-012020-12-3100008951262019-01-012019-12-310000895126us-gaap:GeneralAndAdministrativeExpenseMember2022-01-012022-12-310000895126us-gaap:GeneralAndAdministrativeExpenseMember2021-02-102021-12-310000895126us-gaap:GeneralAndAdministrativeExpenseMember2021-01-012021-02-090000895126us-gaap:GeneralAndAdministrativeExpenseMember2020-01-012020-12-310000895126us-gaap:OilAndGasPropertiesMember2022-01-012022-12-310000895126us-gaap:OilAndGasPropertiesMember2021-02-102021-12-310000895126us-gaap:OilAndGasPropertiesMember2021-01-012021-02-090000895126us-gaap:OilAndGasPropertiesMember2020-01-012020-12-310000895126chk:NaturalGasOilAndNGLProductionMember2022-01-012022-12-310000895126chk:NaturalGasOilAndNGLProductionMember2021-02-102021-12-310000895126chk:NaturalGasOilAndNGLProductionMember2021-01-012021-02-090000895126chk:NaturalGasOilAndNGLProductionMember2020-01-012020-12-310000895126srt:MaximumMemberchk:ChesapeakeEnergyCorporationSavingsandIncentiveStockBonusPlanMember2022-01-012022-12-310000895126srt:MaximumMemberchk:ChesapeakeEnergyCorporationSavingsandIncentiveStockBonusPlanMember2021-04-012021-04-300000895126srt:MaximumMemberchk:ChesapeakeEnergyCorporationSavingsandIncentiveStockBonusPlanMember2021-05-012022-12-310000895126srt:MaximumMember2022-01-012022-12-310000895126chk:ChesapeakeEnergyCorporationSavingsandIncentiveStockBonusPlanMember2022-01-012022-12-310000895126chk:ChesapeakeEnergyCorporationSavingsandIncentiveStockBonusPlanMember2021-02-102021-12-310000895126chk:ChesapeakeEnergyCorporationSavingsandIncentiveStockBonusPlanMember2021-01-012021-02-090000895126chk:ChesapeakeEnergyCorporationSavingsandIncentiveStockBonusPlanMember2020-01-012020-12-310000895126us-gaap:DesignatedAsHedgingInstrumentMember2022-12-31chk:derivative0000895126us-gaap:DesignatedAsHedgingInstrumentMember2021-12-310000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMemberchk:EagleFordMember2022-01-012022-12-31utr:Bcfutr:MMBbls0000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMemberus-gaap:SwapMember2022-01-012022-12-310000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMemberus-gaap:SwapMember2022-12-310000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMemberus-gaap:SwapMember2021-01-012021-12-310000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMemberus-gaap:SwapMember2021-12-310000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMemberchk:CollarMember2022-01-012022-12-310000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMemberchk:CollarMember2022-12-310000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMemberchk:CollarMember2021-01-012021-12-310000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMemberchk:CollarMember2021-12-310000895126srt:NaturalGasReservesMemberchk:ThreeWayCollarsMemberus-gaap:EnergyRelatedDerivativeMember2022-01-012022-12-310000895126srt:NaturalGasReservesMemberchk:ThreeWayCollarsMemberus-gaap:EnergyRelatedDerivativeMember2022-12-310000895126srt:NaturalGasReservesMemberchk:ThreeWayCollarsMemberus-gaap:EnergyRelatedDerivativeMember2021-01-012021-12-310000895126srt:NaturalGasReservesMemberchk:ThreeWayCollarsMemberus-gaap:EnergyRelatedDerivativeMember2021-12-310000895126srt:NaturalGasReservesMemberus-gaap:CallOptionMemberus-gaap:EnergyRelatedDerivativeMember2022-01-012022-12-310000895126srt:NaturalGasReservesMemberus-gaap:CallOptionMemberus-gaap:EnergyRelatedDerivativeMember2022-12-310000895126srt:NaturalGasReservesMemberus-gaap:CallOptionMemberus-gaap:EnergyRelatedDerivativeMember2021-01-012021-12-310000895126srt:NaturalGasReservesMemberus-gaap:CallOptionMemberus-gaap:EnergyRelatedDerivativeMember2021-12-310000895126srt:NaturalGasReservesMemberus-gaap:BasisSwapMemberus-gaap:EnergyRelatedDerivativeMember2022-01-012022-12-310000895126srt:NaturalGasReservesMemberus-gaap:BasisSwapMemberus-gaap:EnergyRelatedDerivativeMember2022-12-310000895126srt:NaturalGasReservesMemberus-gaap:BasisSwapMemberus-gaap:EnergyRelatedDerivativeMember2021-01-012021-12-310000895126srt:NaturalGasReservesMemberus-gaap:BasisSwapMemberus-gaap:EnergyRelatedDerivativeMember2021-12-310000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMember2022-01-012022-12-310000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMember2022-12-310000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMember2021-01-012021-12-310000895126srt:NaturalGasReservesMemberus-gaap:EnergyRelatedDerivativeMember2021-12-310000895126srt:OilReservesMemberus-gaap:EnergyRelatedDerivativeMemberus-gaap:SwapMember2022-01-012022-12-310000895126srt:OilReservesMemberus-gaap:EnergyRelatedDerivativeMemberus-gaap:SwapMember2022-12-310000895126srt:OilReservesMemberus-gaap:EnergyRelatedDerivativeMemberus-gaap:SwapMember2021-01-012021-12-310000895126srt:OilReservesMemberus-gaap:EnergyRelatedDerivativeMemberus-gaap:SwapMember2021-12-310000895126srt:OilReservesMemberus-gaap:EnergyRelatedDerivativeMemberchk:CollarMember2022-01-012022-12-310000895126srt:OilReservesMemberus-gaap:EnergyRelatedDerivativeMemberchk:CollarMember2022-12-310000895126srt:OilReservesMemberus-gaap:EnergyRelatedDerivativeMemberchk:CollarMember2021-01-012021-12-310000895126srt:OilReservesMemberus-gaap:EnergyRelatedDerivativeMemberchk:CollarMember2021-12-310000895126srt:OilReservesMemberus-gaap:BasisSwapMemberus-gaap:EnergyRelatedDerivativeMember2022-01-012022-12-310000895126srt:OilReservesMemberus-gaap:BasisSwapMemberus-gaap:EnergyRelatedDerivativeMember2022-12-310000895126srt:OilReservesMemberus-gaap:BasisSwapMemberus-gaap:EnergyRelatedDerivativeMember2021-01-012021-12-310000895126srt:OilReservesMemberus-gaap:BasisSwapMemberus-gaap:EnergyRelatedDerivativeMember2021-12-310000895126srt:OilReservesMemberus-gaap:EnergyRelatedDerivativeMember2022-01-012022-12-310000895126srt:OilReservesMemberus-gaap:EnergyRelatedDerivativeMember2022-12-310000895126srt:OilReservesMemberus-gaap:EnergyRelatedDerivativeMember2021-01-012021-12-310000895126srt:OilReservesMemberus-gaap:EnergyRelatedDerivativeMember2021-12-310000895126us-gaap:EnergyRelatedDerivativeMember2022-12-310000895126us-gaap:EnergyRelatedDerivativeMember2021-12-310000895126us-gaap:NondesignatedMemberus-gaap:OtherCurrentAssetsMemberus-gaap:CommodityContractMember2022-12-310000895126us-gaap:NondesignatedMemberus-gaap:CommodityContractMember2022-12-310000895126us-gaap:NondesignatedMemberus-gaap:OtherNoncurrentAssetsMemberus-gaap:CommodityContractMember2022-12-310000895126us-gaap:NondesignatedMemberus-gaap:OtherCurrentLiabilitiesMemberus-gaap:CommodityContractMember2022-12-310000895126us-gaap:NondesignatedMemberus-gaap:CommodityContractMemberus-gaap:OtherNoncurrentLiabilitiesMember2022-12-310000895126us-gaap:NondesignatedMemberus-gaap:OtherCurrentAssetsMemberus-gaap:CommodityContractMember2021-12-310000895126us-gaap:NondesignatedMemberus-gaap:CommodityContractMember2021-12-310000895126us-gaap:NondesignatedMemberus-gaap:OtherCurrentLiabilitiesMemberus-gaap:CommodityContractMember2021-12-310000895126us-gaap:NondesignatedMemberus-gaap:CommodityContractMemberus-gaap:OtherNoncurrentLiabilitiesMember2021-12-310000895126us-gaap:CreditRiskMember2022-12-31chk:counterparty0000895126us-gaap:CashFlowHedgingMember2020-12-310000895126us-gaap:CashFlowHedgingMember2019-12-310000895126us-gaap:CashFlowHedgingMember2021-01-012021-02-090000895126us-gaap:CashFlowHedgingMember2020-01-012020-12-310000895126us-gaap:CashFlowHedgingMember2021-02-090000895126us-gaap:BuildingAndBuildingImprovementsMember2022-12-310000895126us-gaap:BuildingAndBuildingImprovementsMember2021-12-310000895126us-gaap:BuildingAndBuildingImprovementsMembersrt:MinimumMember2022-01-012022-12-310000895126srt:MaximumMemberus-gaap:BuildingAndBuildingImprovementsMember2022-01-012022-12-310000895126us-gaap:ComputerEquipmentMember2022-12-310000895126us-gaap:ComputerEquipmentMember2021-12-310000895126us-gaap:ComputerEquipmentMember2022-01-012022-12-310000895126us-gaap:LandMember2022-12-310000895126us-gaap:LandMember2021-12-310000895126us-gaap:MineDevelopmentMember2022-12-310000895126us-gaap:MineDevelopmentMember2021-12-310000895126srt:MinimumMemberus-gaap:MineDevelopmentMember2022-01-012022-12-310000895126srt:MaximumMemberus-gaap:MineDevelopmentMember2022-01-012022-12-310000895126us-gaap:PropertyPlantAndEquipmentOtherTypesMember2022-12-310000895126us-gaap:PropertyPlantAndEquipmentOtherTypesMember2021-12-310000895126srt:MinimumMemberus-gaap:PropertyPlantAndEquipmentOtherTypesMember2022-01-012022-12-310000895126srt:MaximumMemberus-gaap:PropertyPlantAndEquipmentOtherTypesMember2022-01-012022-12-310000895126chk:MomentumSustainableVenturesLLCMemberus-gaap:ScenarioPlanMember2022-12-31chk:billionOfCubicFeetPerDayutr:MT0000895126chk:MomentumSustainableVenturesLLCMember2022-12-310000895126chk:FtsInternationalIncMember2020-01-012020-12-310000895126chk:FtsInternationalIncMember2020-11-180000895126chk:FtsInternationalIncMembersrt:MaximumMember2020-11-190000895126us-gaap:OilAndGasPropertiesMember2020-12-310000895126us-gaap:OilAndGasPropertiesMember2020-01-012020-12-310000895126chk:SandMineMember2020-01-012020-12-310000895126chk:CompressorMember2020-01-012020-12-310000895126chk:MarcellusMember2022-01-012022-12-310000895126chk:VineEnergyCorporationVineMember2021-02-102021-12-310000895126chk:PowderRiverBasinMember2022-01-012022-12-310000895126chk:EagleFordMember2022-01-012022-12-310000895126srt:ScenarioForecastMemberus-gaap:DisposalGroupDisposedOfBySaleNotDiscontinuedOperationsMemberchk:PortionOfEagleFordAssetsMember2023-01-012023-03-310000895126us-gaap:DisposalGroupDisposedOfBySaleNotDiscontinuedOperationsMemberchk:PortionOfEagleFordAssetsMember2022-12-310000895126srt:ScenarioForecastMemberus-gaap:DisposalGroupDisposedOfBySaleNotDiscontinuedOperationsMemberchk:PortionOfEagleFordAssetsMember2023-04-012023-06-300000895126chk:NetherlandSewellAssociatesIncMember2022-12-310000895126srt:NaturalGasReservesMember2021-12-310000895126srt:OilReservesMember2021-12-310000895126srt:NaturalGasLiquidsReservesMember2021-12-31utr:Bcfe0000895126srt:NaturalGasReservesMember2022-01-012022-12-310000895126srt:OilReservesMember2022-01-012022-12-310000895126srt:NaturalGasLiquidsReservesMember2022-01-012022-12-310000895126srt:NaturalGasReservesMember2022-12-310000895126srt:OilReservesMember2022-12-310000895126srt:NaturalGasLiquidsReservesMember2022-12-310000895126srt:NaturalGasReservesMember2020-12-310000895126srt:OilReservesMember2020-12-310000895126srt:NaturalGasLiquidsReservesMember2020-12-310000895126srt:NaturalGasReservesMember2021-01-012021-12-310000895126srt:OilReservesMember2021-01-012021-12-310000895126srt:NaturalGasLiquidsReservesMember2021-01-012021-12-3100008951262021-01-012021-12-310000895126srt:NaturalGasReservesMember2019-12-310000895126srt:OilReservesMember2019-12-310000895126srt:NaturalGasLiquidsReservesMember2019-12-310000895126srt:NaturalGasReservesMember2020-01-012020-12-310000895126srt:OilReservesMember2020-01-012020-12-310000895126srt:NaturalGasLiquidsReservesMember2020-01-012020-12-310000895126chk:RevisionsDueToDevelopmentPlanOptimizationMember2022-01-012022-12-310000895126chk:RevisionsDueToPerformanceMember2022-01-012022-12-310000895126chk:PriceAdjustmentMember2022-01-012022-12-310000895126srt:NaturalGasPerThousandCubicFeetMember2022-12-31iso4217:USDutr:Mcf0000895126srt:CrudeOilMember2022-12-31iso4217:USDchk:bbl0000895126srt:NaturalGasLiquidsReservesMember2022-12-310000895126chk:RevisionsDueToLateralLengthAdjustmentsMember2021-01-012021-12-310000895126chk:PriceAdjustmentMember2021-01-012021-12-310000895126srt:NaturalGasPerThousandCubicFeetMember2021-12-310000895126srt:CrudeOilMember2021-12-310000895126srt:NaturalGasLiquidsReservesMember2021-12-310000895126chk:MarketConditionsMember2020-01-012020-12-310000895126chk:PriceAdjustmentMember2020-01-012020-12-310000895126chk:RevisionsDueToPerformanceMember2020-01-012020-12-310000895126srt:NaturalGasPerThousandCubicFeetMember2020-12-310000895126srt:CrudeOilMember2020-12-310000895126srt:NaturalGasLiquidsReservesMember2020-12-31iso4217:USDutr:bbl0000895126chk:FutureDevelopmentCostsMember2022-12-310000895126chk:FutureDevelopmentCostsMember2021-12-310000895126chk:FutureDevelopmentCostsMember2020-12-31



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2022
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File No. 001-13726
chk-20221231_g1.jpg
CHESAPEAKE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Oklahoma
73-1395733
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
6100 North Western Avenue,
Oklahoma City,
Oklahoma
73118
(Address of principal executive offices)(Zip Code)
(405)
 848-8000
(Registrant’s telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each ClassTrading Symbol(s)Name of Each Exchange on Which Registered
Common Stock, $0.01 par value per shareCHKThe Nasdaq Stock Market LLC
Class A Warrants to purchase Common StockCHKEWThe Nasdaq Stock Market LLC
Class B Warrants to purchase Common StockCHKEZThe Nasdaq Stock Market LLC
Class C Warrants to purchase Common StockCHKELThe Nasdaq Stock Market LLC
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes      No 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes      No 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes     No  
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes     No  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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   Accelerated Filer   Non-accelerated Filer  
Smaller Reporting Company   Emerging Growth Company  



If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes    No  
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes No 
The aggregate market value of our common stock held by non-affiliates on June 30, 2022, was approximately $3.6 billion. As of February 16, 2023, there were 134,719,821 shares of our $0.01 par value common stock outstanding.
__________________________________________
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2023 Annual Meeting of Stockholders are incorporated by reference in Part III.




CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
FORM 10-K
TABLE OF CONTENTS
PART I
Page
PART II
PART III
PART IV

3



Definitions
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Chesapeake,” the “Company” and “Registrant” refer to Chesapeake Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. Certain reserves and production information was previously disclosed in a per barrel of oil equivalent, since the majority of our production profile consists of natural gas, we have converted this information, including prior periods, from a per barrel of oil equivalent, to a per one thousand cubic feet of natural gas equivalent, referred to, on such a converted basis, as per Mcfe. In addition, the following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K (this “Form 10-K” or this “report”):
“Adjusted Free Cash Flow” (a non-GAAP measure) means net cash provided by operating activities (GAAP) less cash capital expenditures and contributions to investments, adjusted to exclude certain items management believes affect the comparability of operating results.
“ASC” means Accounting Standards Codification.
“Backstop Commitment Agreement” means that certain Backstop Commitment Agreement, dated as of June 28, 2020, by and between Chesapeake and the Backstop Parties, as may be further amended, modified, or supplemented from time to time, in accordance with its terms.
“Backstop Parties” means the members of the FLLO Ad Hoc Group that are signatories to the Backstop Commitment Agreement and Franklin Advisers, Inc., as investment manager on behalf of certain funds and accounts.
“Bankruptcy Code” means Title 11 of the United States Code, 11 U.S.C. §§ 101–1532, as amended.
“Bankruptcy Court” means the United States Bankruptcy Court for the Southern District of Texas.
“Bbl” or “Bbls” means barrel or barrels.
“Bcf” means billion cubic feet.
“Bcfe” means billion cubic feet of natural gas equivalent.
“BLM” means the Bureau of Land Management.
“Chapter 11 Cases” means, when used with reference to a particular Debtor, the case pending for that Debtor under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court, and when used with reference to all the Debtors, the procedurally consolidated Chapter 11 cases pending for the Debtors in the Bankruptcy Court.
“Chief” means Chief E&D Holdings, LP.
“Class A Warrants” means warrants to purchase 10 percent of the New Common Stock (after giving effect to the Rights Offering, but subject to dilution by the Management Incentive Plan, the Class B Warrants, and the Class C Warrants), at an initial exercise price per share of $27.63. The Class A Warrants are exercisable from the Effective Date until February 9, 2026.
“Class B Warrants” means warrants to purchase 10 percent of the New Common Stock (after giving effect to the Rights Offering, but subject to dilution by the Management Incentive Plan and the Class C Warrants), at an initial exercise price per share of $32.13. The Class B Warrants are exercisable from the Effective Date until February 9, 2026.
“Class C Warrants” means warrants to purchase 10 percent of the New Common Stock (after giving effect to the Rights Offering, but subject to dilution by the Management Incentive Plan), at an initial exercise price per share of $36.18. The Class C Warrants are exercisable from the Effective Date until February 9, 2026.
4

“Completion” means the process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, oil or natural gas liquids, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.
“Confirmation Order” means the order confirming the Fifth Amended Joint Chapter 11 Plan of Reorganization of Chesapeake Energy Corporation and its Debtor Affiliates, Docket No. 2915, entered by the Bankruptcy Court on January 16, 2021.
“DD&A” means depreciation, depletion and amortization.
“Debtors” means the Company, together with all of its direct and indirect subsidiaries that have filed the Chapter 11 Cases.
“DEI” means diversity, equity and inclusion.
“Developed Acreage” means acres which are allocated or assignable to producing wells or wells capable of production.
“DIP Facility” means that certain debtor-in-possession financing facility documented pursuant to the DIP Documents and DIP Order.
“Dry Well” means a well found to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well.
“Effective Date” means February 9, 2021.
“ESG” means environmental, social and governance.
“Exit Credit Facility” means the reserve-based credit facility available upon emergence from bankruptcy. In December 2022, we terminated the Exit Credit Facility.
“Exploratory Well” means a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir.
“FLLO Term Loan Facility” means the facility outstanding under the FLLO Term Loan Facility Credit Agreement.
“FLLO Term Loan Facility Credit Agreement” means that certain Term Loan Agreement, dated as of December 19, 2019 ((i) as supplemented by that certain Class A Term Loan Supplement, dated as of December 19, 2019 (as amended, restated or otherwise modified from time to time), by and among Chesapeake, as borrower, the Debtor guarantors party thereto, GLAS USA LLC, as administrative agent, and the lenders party thereto, and (ii) as further amended, restated, or otherwise modified from time to time), by and among Chesapeake, the Debtor guarantors party thereto, GLAS USA LLC, as administrative agent, and the lenders party thereto.
“Formation” means a succession of sedimentary beds that were deposited under the same general geologic conditions.
“Free Cash Flow” (a non-GAAP measure) means net cash provided by operating activities (GAAP) less cash capital expenditures.
“G&A” means general and administrative expenses.
“GAAP” means U.S. generally accepted accounting principles.
“General Unsecured Claim” means any Claim against any Debtor that is not otherwise paid in full during the Chapter 11 Cases pursuant to an order of the Bankruptcy Court and is not an Administrative Claim, a Priority Tax Claim, an Other Priority Claim, an Other Secured Claim, a Revolving Credit Facility Claim, a FLLO Term Loan Facility Claim, a Second Lien Notes Claim, an Unsecured Notes Claim, an Intercompany Claim, or a Section 510(b) Claim.
“Gross Acres or Gross Wells” means the total acres or wells, as the case may be, in which a working interest is owned.
5

“LTIP” means the Chesapeake Energy Corporation 2021 Long Term Incentive Plan.
“LNG” means liquefied natural gas.
“Marcellus Acquisition” means Chesapeake’s acquisition of Chief and associated non-operated interests held by affiliates of Radler and Tug Hill, Inc., which closed on March 9, 2022, with an effective date of January 1, 2022.
“MBbls” means thousand barrels.
“MMBbls” means million barrels.
“Mcf” means thousand cubic feet.
“Mcfe” means one thousand cubic feet of natural gas equivalent, with one barrel of oil or NGL converted to an equivalent volume of natural gas using the ratio of one barrel of oil or NGL to six Mcf of natural gas.
“MMcf” means million cubic feet.
“MMcfe” means million cubic feet of natural gas equivalent.
“Net Acres or Net Wells” means the sum of the fractional working interests owned in gross acres or gross wells.
“New Common Stock” means the single class of common stock issued by Reorganized Chesapeake on the Effective Date.
“New Credit Facility” means the reserve-based credit facility entered into on December 9, 2022.
“NGL” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“OPEC+” means Organization of the Petroleum Exporting Countries Plus.
“Petition Date” means June 28, 2020, the date on which the Debtors commenced the Chapter 11 Cases.
“Plan” means the Fifth Amended Joint Chapter 11 Plan of Reorganization of Chesapeake Energy Corporation and its Debtor Affiliates, attached as Exhibit A to the Confirmation Order.
“Play” means a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential natural gas, oil and NGL reserves.
“Present Value of Estimated Future Net Revenues or PV-10 (non-GAAP)” means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average natural gas and oil price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.
“Price Differential” means the difference in the price of natural gas, oil or NGL received at the sales point and the NYMEX price.
“Productive Well” means a well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.
“Proved Developed Reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
“Proved Properties” means properties with proved reserves.
6

“Proved Reserves” has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which states in part proved natural gas and oil reserves are those quantities of natural gas and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
“Proved Undeveloped Reserves (PUDs)” means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
“Put Option Premium” means a nonrefundable aggregate fee of $60 million, which represents 10 percent of the Rights Offering Amount, payable to the Backstop Parties in accordance with, and subject to the terms of the Backstop Commitment Agreement based on their respective backstop commitment percentages at the time such payment is made.
“Radler” means Radler 2000 Limited Partnership.
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“Rights Offering” means the New Common Stock rights offering for the Rights Offering Amount consummated by the Debtors on the Effective Date.
“SEC” means United States Securities and Exchange Commission.
“Second Lien Notes” means the 11.50% senior notes due 2025 issued by Chesapeake pursuant to the Second Lien Notes Indenture.
“Second Lien Notes Claim” means any Claim on account of the Second Lien Notes.
“SOFR” means a rate equal to the secured overnight financing rate as administered by the SOFR Administrator, the Federal Reserve Bank of New York (or a successor administrator of the secured overnight financing rate).
“Standardized Measure” means the discounted future net cash flows relating to proved reserves based on the means of the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average natural gas and oil price during the preceding 12-month period prior to the end of the current reporting period (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period). The standardized measure differs from the PV-10 measure only because the former includes the effects of estimated future income tax expenses.
“Tcf” means trillion cubic feet.
“Tcfe” means trillion cubic feet of natural gas equivalent.
“Tranche A Loans” means the fully revolving loans made under and on the terms set forth under the Exit Credit Facility which were partially funded on the Effective Date. The Tranche A Loans were repaid in full in connection with our entry into the New Credit Facility.
“Tranche B Loans” means term loans made under and on the terms set forth under the Exit Credit Facility which were fully funded on the Effective Date. The Tranche B Loans were repaid in full in connection with our entry into the New Credit Facility.
7

“Undeveloped Acreage” means acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of natural gas and oil regardless of whether the acreage contains proved reserves.
“Unproved Properties” means properties with no proved reserves.
“Vine” means Vine Energy Inc.
“Vine Acquisition” means Chesapeake’s acquisition of Vine Energy Inc. which closed on November 1, 2021.
“Volumetric Production Payment (VPP)” means a limited-term overriding royalty interest in natural gas and oil reserves that: (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser's only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain the remaining reserves, if any, after the scheduled production volumes have been delivered.
“Warrants” means, collectively, the Class A Warrants, Class B Warrants and Class C Warrants.
“Working Interest” means the operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
“WTI” means West Texas Intermediate.
“/Bbl” means per barrel.
“/Mcf” means per Mcf.
“/Mcfe” means per Mcfe.
“2020 Predecessor Period” means the year ended December 31, 2020.
“2021 Predecessor Period” means the period of January 1, 2021 through February 9, 2021.
“2021 Successor Period” means the period of February 10, 2021 through December 31, 2021.
“2022 Successor Period” means the year ended December 31, 2022.
8

Forward-Looking Statements
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). Forward-looking statements include our current expectations or forecasts of future events, including matters relating to the continuing effects of the impact of inflation and commodity price volatility resulting from Russia’s invasion of Ukraine, COVID-19 and related supply chain constraints, and the impact of each on our business, financial condition, results of operations and cash flows, the potential effects of the Plan on our operations, management, and employees, actions by, or disputes among or between, members of OPEC+ and other foreign oil-exporting countries, market factors, market prices, our ability to meet debt service requirements, our ability to continue to pay cash dividends, the amount and timing of any cash dividends and our ESG initiatives. Forward-looking and other statements in this Form 10-K regarding our environmental, social and other sustainability plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking environmental, social and sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future. Forward-looking statements often address our expected future business, financial performance and financial condition, and often contain words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy.”
Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include:
the ability to execute on our business strategy following emergence from bankruptcy;
the impact of inflation and commodity price volatility resulting from Russia’s invasion of Ukraine, COVID-19 and related supply chain constraints along with the effect on our business, financial condition, employees, contractors, vendors and the global demand for natural gas and oil and U.S. and world financial markets;
our ability to comply with the covenants under the credit agreement for our New Credit Facility and other indebtedness;
risks related to potential acquisitions or dispositions;
our ability to realize anticipated cash cost reductions;
the volatility of natural gas, oil and NGL prices, which are affected by general economic and business conditions, as well as increased demand for (and availability of) alternative fuels and electric vehicles;
a deterioration in general economic, business or industry conditions;
uncertainties inherent in estimating quantities of natural gas, oil and NGL reserves and projecting future rates of production and the amount and timing of development expenditures;
our ability to replace reserves and sustain production;
drilling and operating risks and resulting liabilities;
our ability to generate profits or achieve targeted results in drilling and well operations;
the limitations our level of indebtedness may have on our financial flexibility;
our ability to achieve and maintain ESG certifications, goals and commitments;
our inability to access the capital markets on favorable terms;
the availability of cash flows from operations and other funds to fund cash dividends and repurchases of equity securities, to finance reserve replacement costs and/or satisfy our debt obligations;
write-downs of our natural gas and oil asset carrying values due to low commodity prices;
9

charges incurred in response to market conditions;
limited control over properties we do not operate;
leasehold terms expiring before production can be established;
commodity derivative activities resulting in lower prices realized on natural gas, oil and NGL sales;
the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations;
potential OTC derivatives regulations limiting our ability to hedge against commodity price fluctuations;
adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims;
our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used;
pipeline and gathering system capacity constraints and transportation interruptions;
legislative, regulatory and ESG initiatives addressing environmental concerns, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring or water disposal;
terrorist activities and/or cyber-attacks adversely impacting our operations;
an interruption in operations at our headquarters due to a catastrophic event;
federal and state tax proposals affecting our industry;
competition in the natural gas and oil exploration and production industry;
negative public perceptions of our industry;
effects of purchase price adjustments and indemnity obligations; and
other factors that are described under Risk Factors in Item 1A of Part I of this Form 10-K.
We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation to update this information. We urge you to carefully review and consider the disclosures in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.
10

PART I
ITEM 1.Business
Unless the context otherwise requires, references to “Chesapeake,” the “Company,” “us,” “we” and “our” in this report are to Chesapeake Energy Corporation together with its subsidiaries. Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, and our main telephone number at that location is (405) 848-8000.
Our Business
We are an independent exploration and production company engaged in the acquisition, exploration and development of properties to produce natural gas, oil and NGL from underground reservoirs. We own a large portfolio of onshore U.S. unconventional natural gas and liquids assets, including interests in approximately 8,400 gross natural gas and oil wells.
On August 2, 2022, we announced that our Eagle Ford assets were non-core to our future capital allocation strategy. While continuing to focus our capital on the premium rock, returns and runway of our Marcellus and Haynesville positions, on January 17, 2023, we entered into an agreement to sell a portion of our Eagle Ford assets to WildFire Energy I LLC for $1.425 billion. On February 17, 2023, we entered into an agreement to sell a portion of our remaining Eagle Ford assets to INEOS Energy for $1.4 billion.
On March 25, 2022, we sold our Powder River Basin assets in Wyoming to Continental Resources, Inc. for approximately $450 million.
On March 9, 2022, we completed our acquisition of Chief, Radler and associated non-operated interests held by affiliates of Tug Hill, Inc. (“Tug Hill”). Chief, Radler and Tug Hill held producing assets and an inventory of premium drilling locations in the Marcellus Shale in Northeast Pennsylvania.
On November 1, 2021, we completed our acquisition of Vine, an energy company focused on the development of natural gas properties in stacked Haynesville and Mid-Bossier shale plays in Northwest Louisiana.
On June 28, 2020, we and certain of our subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan in a bench ruling on January 13, 2021 and entered the Confirmation Order on January 16, 2021. The Debtors emerged from bankruptcy on February 9, 2021. Upon emergence, all existing equity was canceled and New Common Stock was issued to the previous holders of our FLLO Term Loan Facility, Second Lien Notes, senior unsecured notes and certain general unsecured creditors whose claims were impaired as a result of our bankruptcy, as well as to other parties as set forth in the Plan, including to other parties participating in a $600 million rights offering. Upon emergence from bankruptcy, we adopted fresh start accounting, which resulted in us becoming a new entity for financial reporting purposes. Accordingly, the consolidated financial statements on or after February 9, 2021 are not comparable to the consolidated financial statements prior to that date. To facilitate our discussion in this report, we refer to the post-emergence reorganized company as the “Successor” and the pre-emergence company as the “Predecessor.” See Note 2 and Note 3 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of our bankruptcy, the resulting reorganization and fresh start accounting.


11


Information About Us
We make available, free of charge on our website at chk.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. Documents and information on our website are not incorporated by reference herein.
The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including Chesapeake, that file electronically with the SEC.
Business Strategy
Our business strategy is to create shareholder value through the responsible development of our significant resource plays, while continuing to be a leading provider of affordable, reliable, low carbon energy to the United States.
Superior Capital Returns. We consistently focus on optimizing the development of our large resource base with a prioritization of generating high cash returns on capital invested. Our drive toward continuous improvement through engineering innovation and planning enhances margins for our shareholders.
Sustainability Leadership. We are committed to protecting our country’s natural resources and reducing our environmental footprint. We continue to foster a focus on environmental excellence through a culture of stewardship and sustainability among our employees and business partners. We recognize that ownership and accountability are key to helping ensure our work sites are safe and protective of the environment.
Premier Balance Sheet. We believe that maintaining low net leverage is integral to our business strategy and will allow us to maintain lower fixed costs, improve our margins and maintain the flexibility of our capital program. We further de-risk our margins and cash flows with prudent natural gas hedging that aims to reduce the impact of volatility.
Operating Areas
We focus our acquisition, exploration, development and production efforts in the geographic operating areas described below.
Marcellus - Northern Appalachian Basin in Pennsylvania.
Haynesville - Haynesville/Bossier Shales in Northwestern Louisiana.
Eagle Ford - Eagle Ford Shale in South Texas. In January 2023, we entered into an agreement to sell a portion of our Eagle Ford assets. In February 2023, we entered into an agreement to sell a portion of our remaining Eagle Ford assets.
12


Well Data
As of December 31, 2022, we held an interest in approximately 8,400 gross productive wells, including 6,700 wells in which we held a working interest and 1,700 wells in which we held an overriding or royalty interest. Of the 6,700 (4,300 net) wells in which we held a working interest, 3,500 (2,100 net) wells were classified as productive natural gas wells and 3,200 (2,200 net) wells were classified as productive oil wells. During 2022, we operated 6,000 gross wells and held a non-operating working interest in 700 gross wells. We also completed 216 gross (151 net) wells as operator and participated in another 22 gross (1 net) wells completed by other operators. We operate approximately 99% of our current daily production volumes.
Drilling Activity
The following table sets forth the wells we completed or participated in during the periods indicated. In the table, "gross" refers to the total wells in which we had a working interest and "net" refers to gross wells multiplied by our working interest:
202220212020
Gross%Net%Gross%Net%Gross%Net%
Development:
Productive237 100 151 100 137 100 74 100 203 100 126 100 
Dry— — — — — — — — — — — — 
Total237 100 151 100 137 100 74 100 203 100 126 100 
Exploratory:
Productive— — — — 100 100 — — — — 
Dry100 100 — — — — 100 100 
Total100 100 100 100 100 100 
The following table shows the wells we completed or participated in by operating area:
202220212020
Gross WellsNet WellsGross WellsNet WellsGross WellsNet Wells
Marcellus103 59 83 34 79 33 
Haynesville83 61 40 31 21 19 
Eagle Ford52 32 12 86 65 
Powder River Basin— — 12 
Mid-Continent— — — — — 
Other— — — — 
Total238 152 139 75 205 128 
As of December 31, 2022, we had 91 gross (59 net) wells in the process of being drilled or completed.
13


Production Volumes, Sales Prices, Production Expenses and Gathering, Processing and Transportation Expenses
The following tables present information regarding our net production volumes, average sales price received for our production, and production and gathering, processing and transportation expenses per Mcfe for the periods indicated for our significant fields:
Production
Natural Gas (Bcf)Oil (MMBbl)NGL (MMBbl)Total (Bcfe)
2022
Marcellus670— — 670
Haynesville588— — 588
Eagle Ford4618.75.8193
Total Production1,30819.46.01,461
2021
Marcellus471— — 471
Haynesville265— — 265
Eagle Ford5122.56.7227
Total Production80725.98.01,010
2020
Marcellus385— — 385
Haynesville198— — 198
Eagle Ford6831.38.9309
Total Production68437.311.3976
Average Sales Price of Production(a)
Expenses ($/Mcfe)
Natural Gas ($/Mcf)Oil ($/Bbl)NGL ($/Bbl)Total ($/Mcfe)ProductionGP&T
2022
Marcellus$6.03 $— $— $6.03 $0.11 $0.57 
Haynesville$5.92 $— $— $5.92 $0.26 $0.53 
Eagle Ford$5.64 $96.10 $36.76 $11.76 $1.22 $1.78 
Total$5.96 $96.07 $37.48 $6.77 $0.33 $0.73 
2021
Marcellus$3.16 $— $— $3.16 $0.08 $0.68 
Haynesville$3.96 $— $— $3.96 $0.24 $0.49 
Eagle Ford$3.84 $67.14 $29.14 $8.40 $0.85 $1.48 
Total$3.49 $67.01 $30.77 $4.75 $0.33 $0.87 
2020
Marcellus$1.64 $— $— $1.64 $0.08 $0.76 
Haynesville$1.83 $— $— $1.83 $0.21 $0.95 
Eagle Ford$1.90 $38.38 $10.93 $4.62 $0.65 $1.54 
Total$1.73 $38.16 $11.55 $2.81 $0.38 $1.11 
___________________________________________
(a) Excludes the effect of hedging.
14

Natural Gas, Oil and NGL Reserves
The tables below set forth information as of December 31, 2022, with respect to our estimated proved reserves, the associated estimated future net revenue, the present value of estimated future net revenue and the standardized measure of discounted future net cash flows. None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated natural gas, oil and NGL reserves we own. All of our estimated reserves are located within the United States.
December 31, 2022
Natural GasOilNGLTotal
(bcf)(mmbbl)(mmbbl)(bcfe)
Proved developed7,385 157.2 58.9 8,681 
Proved undeveloped3,984 41.2 15.0 4,321 
Total proved(a)
11,369 198.4 73.9 13,002 


Proved
Developed
Proved
Undeveloped
Total
Proved
Standardized measure(b)
$26,305 
Estimated future net revenue(b)
$42,773 $18,333 $61,106 
Present value of estimated future net revenue (PV-10)(b)
$22,356 $10,344 $32,700 
___________________________________________
(a)    Marcellus, Haynesville and Eagle Ford accounted for approximately 51%, 31%, and 18%, respectively, of our estimated proved reserves by volume as of December 31, 2022.
(b)    Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using pricing differentials and costs under existing economic conditions as of December 31, 2022, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2022. The prices used in our PV-10 measure were $6.36 per mcf of natural gas, $93.67 per bbl of oil and $43.58 per bbl of NGL, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2022. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense of $6.4 billion as of December 31, 2022.
Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10, a non-GAAP measure, should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.
A comparison of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved natural gas and oil reserves.
15

As of December 31, 2022, our proved reserve estimates included 4,321 Bcfe of reserves classified as proved undeveloped, compared to 3,963 Bcfe as of December 31, 2021. Presented below is a summary of changes in our proved undeveloped reserves for 2022:
Total
(bcfe)
Proved undeveloped reserves, beginning of period3,963 
Extensions and discoveries51 
Revisions of previous estimates866 
Conversion to proved developed reserves(1,099)
Purchase of reserves-in-place552 
Sales of reserves-in-place(12)
Proved undeveloped reserves, end of period4,321 

As of December 31, 2022, all PUDs were planned to be developed within five years of original recording. In 2022, we invested approximately $851 million to convert 1,099 bcfe of PUDs to proved developed reserves. We added 51 bcfe of PUD reserves through extensions and discoveries primarily due to new PUDs added to emerging plays. Revisions of previous estimates resulted in a net upward revision of 866 bcfe. The net upward revision primarily resulted from development plan optimization through prioritizing longer laterals and multi-well pad development in Haynesville for 834 bcfe, 146 bcfe of upward revisions to existing PUD forecasts in Marcellus and Haynesville, partially offset by a downward revision of 114 bcfe due to development plan changes in Marcellus and Eagle Ford. We added 552 bcfe of PUDs through purchase of reserves-in-place related to the Marcellus Acquisition.
The future net revenue attributable to our estimated PUDs was $18.333 billion and the present value was $10.344 billion as of December 31, 2022. These values were calculated assuming that we will expend approximately $4.3 billion to develop these reserves ($1,411 million in 2023, $1,430 million in 2024, $1,184 million in 2025, $165 million in 2026 and $56 million in 2027). The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs, commodity prices and the availability of capital. Our developmental drilling schedules are subject to revision and reprioritization throughout the year resulting from unknowable factors such as commodity prices, unexpected developmental drilling results, title issues and infrastructure availability or constraints.
Of our 13,002 bcfe of proved reserves as of December 31, 2022, approximately 190 bcfe, or 1%, were non-producing.
Our ownership interest used for calculating proved reserves and the associated estimated future net revenue assumes maximum participation by other parties to our farm-out and participation agreements.
Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves as of December 31, 2022, 2021 and 2020, along with the changes in quantities and standardized measure of the reserves for each of the three years then ended, are shown in Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities included in Item 8 of Part II of this report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured exactly, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. Accordingly, reserve estimates often differ from the actual quantities of natural gas, oil and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. See Supplemental Disclosures About Natural Gas,
16

Oil and NGL Producing Activities included in Item 8 of Part II of this report for further discussion of our reserve quantities.
Reserves Estimation
We engaged Netherland, Sewell & Associates, Inc., a third-party engineering firm, to prepare approximately 92% by volume, and approximately 95% by value, of our estimated proved reserves as of December 31, 2022. A copy of the report issued by the engineering firm is filed with this report as Exhibit 99.1. The qualifications of the technical persons at the firm primarily responsible for overseeing the preparation of our reserve estimates are set forth below.
Over 39 combined years of practical experience in the estimation and evaluation of reserves;
Licensed Professional Engineer in the State of Texas and Bachelor of Science degree in Chemical Engineering;
Licensed Professional Geoscientist in the State of Texas and Bachelor of Science and Master of Science degrees in Geology.
Our Corporate Reserves Department prepared approximately 8% by volume, and approximately 5% by value, of our estimated proved reserves as of December 31, 2022, disclosed in this report. Those estimates were established utilizing standard geological and engineering technologies, which are generally accepted by the petroleum industry and were based upon the best available production, engineering and geologic data. These technologies, including computational methods, provide reasonable certainty in our reserves estimation and include technologies and inputs such as drilling results and well performance, decline curve analysis of wells in analogous reservoirs, material balance, volumetric calculation, statistical analysis, well logs, geologic maps and seismic data.
Our Manager – SEC Reserves Engineering, who is in charge of our Corporate Reserves Department, is the technical person primarily responsible for overseeing the preparation of our reserve estimates and for coordinating any reserves work conducted by a third-party engineering firm. His qualifications include the following:
Over 15 years of practical experience in the oil and gas industry, with over 13 years in reservoir engineering;
Licensed Professional Engineer (Petroleum) in the State of Oklahoma;
Member in good standing of the Society of Petroleum Evaluation Engineers;
Bachelor of Science in Mechanical Engineering; and
Master’s of Business Administration.
We ensure that the key members of our Corporate Reserves Department have appropriate technical qualifications to oversee the preparation of reserve estimates. Our engineering technicians have a minimum of a four-year degree in mathematics, economics, finance or other technical/business/science field. We maintain a continuous education program for our engineers and technicians on new technologies and industry advancements as well as refresher training on basic skills and analytical techniques.
We maintain internal controls such as the following to ensure the reliability of reserves estimations:
We follow comprehensive SEC-compliant internal policies to estimate and report proved reserves. Reserve estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by the Manager – SEC Reserves Engineering.
The Corporate Reserves Department reviews our proved reserves at the close of each quarter.
Each quarter, Reservoir Managers, the Manager – SEC Reserves Engineering, the Senior Resource Manager, the Vice Presidents of each operating area and the Vice President of Corporate and Strategic Planning review all significant reserves changes and all new proved undeveloped reserves additions.    
The Corporate Reserves Department reports independently of our operations.
The five-year PUD development plan is reviewed and approved annually by the Manager – SEC Reserves Engineering, the Senior Resource Manager, and the Vice President of Corporate and Strategic Planning.
17


Acreage
The following table sets forth our gross and net developed and undeveloped natural gas and oil leasehold and fee mineral acreage as of December 31, 2022. Gross acres are the total number of acres in which we own a working interest. Net acres refer to gross acres multiplied by our fractional working interest.
Developed LeaseholdUndeveloped LeaseholdTotal
Gross AcresNet AcresGross AcresNet AcresGross AcresNet Acres
(in thousands)
Marcellus566 330 167 135 733 465 
Haynesville359 322 111 56 470 378 
Eagle Ford681 480 213 117 894 597 
Other(a)
316 293 1,348 1,275 1,664 1,568 
Total1,922 1,425 1,839 1,583 3,761 3,008 
___________________________________________
(a) Includes 1.2 million net acres retained in the 2016 divestiture of our Devonian Shale assets, in which we retained all rights below the base of the Kope formation.
Most of our leases have a three- to five-year primary term, and we manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our drilling to establish production in paying quantities in order to hold leases by production, timely exercising our contractual rights to pay delay rentals to extend the terms of leases we value, planning non-core divestitures to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. We do not anticipate any material lease expirations within the next three years.

Marketing
The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including commodity price structuring, securing and negotiating of gathering, hauling, processing and transportation services, contract administration and nomination services for us and other interest owners in Chesapeake-operated wells. The marketing operations also provide other services for our exploration and production activities, including services to enhance the value of natural gas and oil production by aggregating volumes sold to various intermediary markets, end markets and pipelines. This aggregation allows us to attract larger, more creditworthy customers that in turn assist in maximizing the prices received.
Generally, our natural gas and NGL production are sold to purchasers under percentage-of-index contracts, spot price contracts or percentage-of-proceeds contracts. Under our percentage-of-index contracts, the price we receive is tied to published indices. Under the terms of our percentage-of-proceeds contracts, we receive a percentage of the resale price received from the ultimate purchaser. Oil production is sold under short-to-long term market-sensitive and spot price contracts.
We have entered into long-term gathering, processing, and transportation contracts with various parties that require us to deliver fixed, determinable quantities of production over specified periods of time. Certain of our contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. See Note 7 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of commitments.
As of December 31, 2022, we had delivery commitments for a total of approximately 3,400 bcf over the next 10 years. These delivery commitments vary each year, and we expect to primarily fulfill these commitments with production from our proved developed reserves.
18


Major Customers
For the 2022 Successor Period, sales to Shell Energy North America and Valero Energy Corporation accounted for approximately 13% and 10%, respectively, of total revenues (before the effects of hedging). For the 2021 Successor Period, sales to Valero Energy Corporation and Energy Transfer Crude Marketing accounted for approximately 14% and 11%, respectively, of total revenues (before the effects of hedging). For the 2021 Predecessor Period and 2020 Predecessor Period, sales to Valero Energy Corporation accounted for approximately 19% and 17%, respectively, of total revenues (before the effects of hedging). No other purchasers accounted for more than 10% of our total revenues during the 2022 Successor Period, 2021 Successor Period, 2021 Predecessor Period or 2020 Predecessor Period.

Competition
We compete with both major integrated and other independent natural gas and oil companies in all aspects of our business to explore, develop and operate our properties and market our production. Some of our competitors may have larger financial and other resources than us. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect demand for natural gas and oil production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. We also face indirect competition from alternative energy sources, including wind, solar and electric power. We believe that our technological expertise, combined with our exploration, land, drilling and production capabilities and the experience of our management team, enables us to compete effectively.

Public Policy and Government Regulation
All of our operations are conducted onshore in the United States. Our industry is subject to a wide range of regulations, laws, rules, taxes, fees and other policy implementation actions that have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations that are binding on our industry, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. We actively monitor regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems. The following are significant areas of government control and regulation affecting our operations.
Exploration and Production, Environmental, Health and Safety and Occupational Laws and Regulations
Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:
reporting of workplace injuries and illnesses;
industrial hygiene monitoring;
worker protection and workplace safety;
approval or permits to drill and to conduct operations;
provision of financial assurances (such as bonds) covering drilling and well operations;
calculation and disbursement of royalty payments and production taxes;
seismic operations/data;
location, drilling, cementing and casing of wells;
19

well design and construction of pad and equipment;
construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;
method of well completion and hydraulic fracturing;
water withdrawal;
well production and operations, including processing and gathering systems;
emergency response, contingency plans and spill prevention plans;
emissions and discharges permitting;
climate change;
use, transportation, storage and disposal of fluids and materials incidental to natural gas and oil operations;
surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;
plugging and abandoning of wells; and
transportation of production.
Shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change and requiring agencies to review environmental actions taken by the Trump administration, as well as a memorandum to departments and agencies to refrain from proposing or issuing rules until a departmental or agency head appointed or designated by the Biden administration has reviewed and approved the rule. In November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-carbon dioxide GHG emissions, such as methane and nitrous oxide. Shortly thereafter, in November 2021, the Environmental Protection Agency (the “EPA”) proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The EPA issued a supplemental proposed rule in November 2022 to update, strengthen and expand its November 2021 proposed rule. The supplemental proposed rule would impose more stringent requirements on the natural gas and oil industry. These executive orders and policy priorities may result in the development of additional regulations or changes to existing regulations, certain of which could negatively impact our financial position, results of operations and cash flows. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will take to achieve its GHG emissions targets. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. Although the national commitments in the Paris Agreement create no binding requirements on individual companies or facilities, they do provide indications of the current administration’s policy direction and the types of legislative and regulatory requirements—such as the EPA’s proposed methane rules—that may be needed to achieve those commitments. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. Shortly thereafter, in August 2022, President Biden signed the Inflation Reduction Act of 2022 (the “IRA”) into law, which, among other things, includes a methane emissions reduction program that amends the Clean Air Act to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. Such or similar legislation, regulations and initiatives could affect our business and our results of operation by increasing operating and compliance costs.
20

In addition, several states and geographic regions in the United States have also adopted legislation and regulations regarding climate change-related matters, and additional legislation or regulation by these states and regions, U.S. federal agencies, including the EPA, and/or international agreements to which the United States may become a party could result in increased compliance costs for us and our customers. Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, administrative, civil or criminal fines or penalties or injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the responsibility and costs of environmental protection and safety and health compliance fundamental, manageable parts of our business. To date, we have been able to plan for and comply with environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, as well as the increasing number of climate-related commitments by capital providers, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and may continue to increase. For example, in addition to regulations from the EPA and similar agencies, the SEC has issued proposed rules that would mandate extensive disclosure of climate-related risks and other information. For more information, see Item 1A. Risk Factors - “We are subject to extensive governmental regulation, which can change and could adversely impact our business.” The SEC has also indicated plans to propose various other disclosure regulations, including regarding human capital and other ESG matters. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.
Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from gas and oil wells, and the unitization or pooling of gas and oil properties. In the United States, some states allow the statutory pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop gas and oil properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of gas and oil we can produce from our wells and the number of wells or the locations at which we can drill. For further discussion, see Item 1A. Risk Factors - We are subject to extensive governmental regulation, which can change and could adversely impact our business.
Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could make it difficult or impossible to conduct our drilling and completion operations, and thereby reduce the amount of natural gas, oil and NGL that we are ultimately able to produce from our properties.
Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered the U.S. Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has increased its review in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, gas and oil measurement and royalty payment obligations for production from federal lands. On January 27, 2021, President Biden issued an executive order indefinitely suspending new natural gas and oil leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal gas and oil permitting and leasing practices. The federal district court in Louisiana issued a permanent injunction against the executive order on August 18, 2022, limited to the thirteen plaintiff states, Louisiana, Alabama, Alaska, Arkansas, Georgia, Mississippi, Missouri, Montana, Nebraska, Oklahoma, Texas, Utah, and West Virginia. In response to the January 27, 2021 executive order, the U.S. Department of the Interior released its “Report On The Federal Oil And Gas Leasing Program” in November 2021, which assessed the current state of gas and oil leasing on federal lands and proposed several reforms, including raising royalty rates and implementing stricter standards for entities seeking to purchase gas and oil leases. On November 30, 2022, the BLM issued a proposed rule to reduce the release of methane from venting, flaring, and leaks during gas and oil production activities on Federal and Indian leases, exemplifying the Biden Administration’s increased focus on the climate change impacts of federal projects, which could result in further changes to the federal gas and oil leasing program in the future. Restrictions surrounding onshore drilling, onshore
21

federal lease availability, and restrictions on the ability to obtain required permits could have a material adverse impact on our operations.
Permitting activities on federal lands are also subject to frequent delays. Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.
For further discussion, see Item 1A. Risk Factors - Natural gas and oil operations are uncertain and involve substantial costs and risks.

Title to Properties
Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the natural gas and oil industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the natural gas and oil industry. Nevertheless, we are involved in title disputes from time to time that may result in litigation.

Operating Hazards and Insurance
The natural gas and oil business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.
We maintain a control of well insurance policy with a $50 million single well limit and a $100 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $300 million comprehensive general liability umbrella insurance policy. In addition, we maintain a $50 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.
22


Facilities
We own an office complex in Oklahoma City and we own or lease various field offices in cities or towns in the areas where we conduct our operations.

Executive Officers
Domenic J. Dell'Osso, Jr., President, Chief Executive Officer and Director
Domenic J. (“Nick”) Dell'Osso, Jr., 46, has served as President and Chief Executive Officer since October 2021. Prior to being named as CEO, Mr. Dell’Osso served as our Executive Vice President and Chief Financial Officer since November 2010. Mr. Dell'Osso served as our Vice President – Finance and Chief Financial Officer of our wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010. Before joining Chesapeake, Mr. Dell’Osso was an energy investment banker with Jefferies & Co. from 2006 to 2008 and Banc of America Securities from 2004 to 2006. Mr. Dell’Osso graduated from Boston College in 1998 and from the University of Texas at Austin in 2003.
Mohit Singh, Executive Vice President and Chief Financial Officer
Mohit Singh, 46, was appointed Executive Vice President and Chief Financial Officer in December 2021. Prior to joining Chesapeake, Mr. Singh served for six years on the executive leadership team at BPX Energy, the United States onshore subsidiary of BP (NYSE: BP). He most recently led the M&A, corporate land and reserves functions, having previously served as Head of Business Development and Exploration and as Senior Vice President – North Business Unit. Prior to joining BPX, Mr. Singh worked as an investment banker focused on oil and gas transactions for RBC Capital Markets and Goldman Sachs. A chemical engineer by training, he began his career at Shell Exploration & Production Company where he held business planning, reservoir engineering and research engineering roles of increasing importance. Mr. Singh earned a PhD in Chemical Engineering from the University of Houston, an MBA from the University of Texas and a BTech in Chemical Engineering from the Indian Institute of Technology.
Joshua J. Viets, Executive Vice President and Chief Operating Officer
Joshua J. Viets, 44, was appointed Executive Vice President and Chief Operating Officer in February 2022. Prior to joining Chesapeake, Mr. Viets worked for 20 years in operational positions of increasing importance at ConocoPhillips Company (NYSE: COP). He most recently served as Vice President, Delaware Basin and previously held leadership positions in operations, engineering, subsurface, and capital project across the ConocoPhillips portfolio. Mr. Viets earned a Bachelor of Science in Petroleum Engineering from Colorado School of Mines in 2001.
Benjamin E. Russ, Executive Vice President - General Counsel and Corporate Secretary
Benjamin E. (“Ben”) Russ, 48, was appointed Executive Vice President – General Counsel and Corporate Secretary in June 2021. Prior to that time, he served as Associate General Counsel – Corporate from May 2014 to June 2021; Division Counsel/Senior Division Counsel managing day-to-day legal matters in the Barnett, East Texas and Louisiana from July 2010 to May 2014; and Attorney/Senior Attorney managing litigation in Louisiana from September 2008 to July 2010. Before joining Chesapeake, Mr. Russ worked at Gulfport Energy Corporation serving as Assistant General Counsel from 2005 to 2006 and General Counsel from 2006 to 2008. Prior to Gulfport, he was an associate at the McKinney & Stringer, P.C. Mr. Russ received a B.S. in Finance from Oklahoma State University in 1996 and a J.D. from Oklahoma City University in 2004.
23

Human Capital Resources
One Team. One Chesapeake.
Our “One CHK” culture and company core values promote an inclusive, diverse and productive workplace. Working as One CHK defines Chesapeake’s culture and unites our team to achieve shared goals for the benefit of our stakeholders. It is a culture of accountability where innovation, collaboration and calculated risk-taking help us achieve sustainable operational success. We had approximately 1,200 employees as of December 31, 2022. None of our employees were covered by collective bargaining agreements, and our management works to maintain good relations with our employees.
Our Culture, Our Core Values
At Chesapeake, our employees are driven to create value every day in a safe and responsible manner. Our core values are the foundation of our culture and the driving force behind our goal to achieve ESG excellence. Serving as the lens through which we evaluate every business decision, our commitment to these values, in both words and actions builds a stronger, healthier Chesapeake, benefiting all our stakeholders. Our core values are:
Integrity and Trust
Respect
Transparency and Open Communication
Commercial Focus
Change Leadership
Celebrating Diversity, Equity and Inclusion
We are committed to inclusion and diversity. Building a diverse workforce and equitable and inclusive work culture is an important factor in contributing to Chesapeake’s sustainable success. We proactively embrace our diversity of people, thoughts and talents, and combine these strengths to pursue results and meaningful change for our company, employees and stakeholders, and we provide education and training for our employees on topics related to inclusion and diversity.
In 2019, Chesapeake joined a coalition of companies pledging to advance diversity and inclusion in the workplace. On February 9, 2021, we formed a board committee dedicated to ESG oversight, including our inclusion and diversity efforts. Two of the seven members of our Board of Directors are considered diverse, including one female and one “underrepresented minority” (as defined in Nasdaq’s newly enacted listing rule). Chesapeake cultivates a workplace in which diverse perspectives are welcomed and respected and where employees feel encouraged to discuss diversity and inclusion.
In 2022, we further advanced our DEI program by nominating an executive sponsor from the Company’s senior management team, along with our inaugural advisory board and council teams. Each of these branches of our DEI program take part in determining strategic priorities, advancing our culture and supporting internal activities that invite all employees to participate in achieving our DEI vision.
Stay Accident Free Everyday (S.A.F.E.)
Safety is more than a company metric, it is core to our commitment to leading a responsible energy future. We set and deliver robust safety standards, prioritizing the well-being of our employees and contractors. Our safety culture is championed by our Board of Directors and executive leadership team, owned by every employee and contractor and managed by our Health, Safety, Environmental and Regulatory (HSER) team. Maintaining a safe work environment and promoting safe behaviors is a commitment that each of our employees and contractors own together. We hold each other accountable to keeping our sites, our co-workers and our contractors safe.
One program that reinforces this philosophy of personal responsibility is Stop Work Authority. Through Stop Work Authority, every employee and contractor has the right, responsibility and authority to stop work if conditions are unsafe or could cause harm to the environment. Creating an incident-free work environment starts with setting clear expectations among employees and contractors regarding our safety standards, and working to empower and equip individuals with the skills necessary to promote safety in their areas of work. The foundation of our safety
24

training efforts is our Stay Accident Free Every Day (S.A.F.E.) program, which encourages all workers on our locations to take personal responsibility for their safety and the safety of those around them. This behavior-based program addresses the activities that can often lead to safety incidents and encourages actions that create safe work sites and a safe corporate campus.
Every year our HSER team provides targeted trainings based on safety performance analysis, job functions and location specific factors. Our training program includes a mix of in-person and virtual training, with greater emphasis on in-person instruction and includes all employees. Job-specific learning paths aim to exceed regulatory requirements and ensure employees are holistically prepared to execute their job functions safely and responsibly.

Chesapeake’s training philosophy values contractor training in the same manner as employees. We design contractor training to align as much as possible with employee training, encouraging synchronized knowledge sharing and understanding, critical to decreasing our cumulative incidents.
Ethical Business Conduct
Chesapeake works hard to maintain the confidence of our stakeholders. We earn this trust by acting in an ethical manner to protect our people, the environment and the communities where we operate. This starts by driving accountability through all levels of the company and having systems in place to uphold our high standards for conduct. Strong governance practices begin at the top providing our organization with clear guidelines to define standards for ethical behavior at every level. Each Chesapeake director or employee, regardless of position, must abide by Chesapeake’s Code of Business Conduct (the "Code"), which is structured around our core values. Each year all employees must sign a Code certification confirming they have reviewed the Code and related policies, understand the high standards expected of them and will report actual or potential ethics concerns or Code violations.
Employee Wellness and Benefits
Supporting the individual well-being of our employees is foundational to our safety culture and success as a company. We champion healthy lifestyles and offer health resources. Across the company, employees are offered preventive programs and are encouraged to complete an annual screening for common health-related issues. We support our employees’ and their families’ health by offering full medical, dental, vision, prescription drug insurance for employees and their families, life insurance, short- and long-term disability coverage, and health savings and dependent care flexible spending accounts. We offer parental leave for the birth or adoption of a child, an adoption assistance program, alternate work schedules, a 401(k) savings plan with company match and discretionary contributions, flexible work hours, generous paid time off and 12 company-paid holidays, tuition reimbursement and access to a child development center and fitness center at market rates. Additionally, Chesapeake provides employees and their families access to a confidential Employee Assistance Program (EAP) which connects employees with trained counselors and other support professionals.
25

Item 1A.Risk Factors
There are numerous factors that affect our business and results of operations, many of which are beyond our control. The following is a description of factors that we consider to be material and that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, results of operations, cash flows, reserves and/or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities.
Risks Related to Operating our Business
Conservation measures and technological advances could reduce demand for natural gas and oil.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to natural gas and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas and oil. The impact of the changing demand for natural gas and oil could adversely impact our earnings, cash flows and financial position.
Negative public perception regarding us or our industry could have an adverse effect on our operations.
Negative public perception regarding us or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities may lead to generally increased political pressure and regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations through organized protests, attempts to block or sabotage our operations or those of our midstream transportation providers, encourage capital providers to divest of their interests in us or our industry, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation, as well as potentially reducing our ability to execute routine or strategic business partnerships. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business. A change in control of national, state or local governments, including the U.S. presidential administration, Congress, state or local governments, and governments of other countries may also result in uncertainty regarding the degree to which there will be increased restrictions on natural gas and oil production activities, which could materially adversely affect our industry and our financial condition and results of operations.
Certain financial institutions, funds and other sources of capital have also elected to restrict or eliminate their investment in certain fossil fuel-related activities. For example, many large financial institutions have announced commitments to reduce the emissions associated with their financing activities, such as through the Glasgow Financial Alliance for Net Zero (“GFANZ”), whose members represent over $130 trillion in capital subject to a goal of net zero financed emissions by 2050. Ultimately, this could make it more difficult or costly for us to secure funding for exploration and production activities. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to GHGs and climate change, before investing in our common stock or providing financing. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, regardless of whether such efforts are successful, and we may be forced to implement technologies that are less economically efficient or are not economically viable in order to improve our sustainability performance and to meet the specific requirements to perform services for certain customers. For more information, see our risk factor “Increasing attention to ESG matters and our ability to achieve and maintain ESG certifications, goals and commitments may impact our business, financial results or stock price.”
26

Risks related to potential acquisitions or dispositions may adversely affect our business.
From time to time, we evaluate acquisitions and dispositions of assets, businesses and other investments. These transactions may not result in the anticipated benefits or efficiencies. In addition, acquisitions may be financed by borrowings, requiring us to incur more debt, or by the issuance of our common stock. Any such acquisition or disposition involves risks and we cannot assure you that:
any acquisition will be successfully integrated into our operations and internal controls;
the due diligence conducted prior to an acquisition will uncover situations that could result in financial or legal exposure, such as title defects and potential environmental and other liabilities;
post-closing purchase price adjustments will be realized in our favor;
our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating expenses and costs will be accurate;
there will not be delays in closing, lower than expected sales proceeds for the disposed assets or business, residual liabilities, or post-closing claims for indemnification;
any investment, acquisition, or disposition will not divert management resources from the operation of our business; and
any investment, acquisition, or disposition will not have a material adverse effect on our financial condition, results of operations, cash flows or reserves.
If any of these risks materialize, the benefits of such acquisition or disposition may not be fully realized, if at all, and our financial condition, results of operations, cash flows and reserves could be negatively impacted.
The gas and oil exploration and production industry is very competitive; some of our competitors have greater financial and other resources than we do, and there is competition to attract and retain talent and competition over access to certain industry equipment.
We face competition in every aspect of our business, including, but not limited to, buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing natural gas, oil or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do. As a result, these competitors may be able to address industry challenges more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.
Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively may be diminished. We also compete for the equipment required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield equipment and services, which could adversely affect our ability to execute our development plans on a timely basis and within budget.
Natural gas, oil and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.
Our revenues, results of operations, profitability, liquidity, leverage ratio and ability to grow and invest in capital expenditures depend primarily upon the prices we receive for the natural gas, oil and NGL we sell. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low natural gas, oil and NGL prices can negatively affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, periods of low natural gas and oil prices may result in a reduction of the carrying value of our natural gas and oil properties due to recognizing impairments in proved and unproved properties.
27

Volatility in natural gas, oil and NGL prices may result from factors that are beyond our control, including:
domestic and worldwide supplies of natural gas, oil and NGL, including U.S. inventories of natural gas and oil reserves;
weather conditions;
changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns, such as the COVID-19 pandemic;
the price and availability of alternative fuels;
technological advances affecting energy consumption;
the effectiveness of worldwide conservation measures;
the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;
the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
U.S. exports of natural gas, oil, liquefied natural gas and NGL;
the price and level of foreign imports;
the nature and extent of domestic and foreign governmental regulations and taxes;
the ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and others to agree to and maintain oil price and production controls;
increased use of competing energy products, including alternative energy sources;
political instability or armed conflict in natural gas and oil producing regions, including in connection with the ongoing conflict between Russia and Ukraine;
acts of terrorism; and
domestic and global economic and political conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and NGL price movements. In addition, any prolonged period of lower prices could reduce the quantities of reserves that we may economically produce.
The ongoing COVID-19 pandemic and related economic turmoil, including supply chain constraints, have affected, and could continue to adversely affect, our business, financial condition, results of operations and cash flows.
The global spread of COVID-19 created significant volatility, uncertainty, and economic disruption, including supply chain constraints, commencing in 2020, and threatens to continue to do so in 2023. The pandemic has adversely impacted the entire global economy, and there is considerable uncertainty regarding how long the pandemic and related market conditions will persist and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as quarantines, shelter-in-place orders, business and government shutdowns and restrictions on operations. Our precautionary measures and plans may not be effective in preventing future disruptions to our business. Moreover, future operations could be negatively affected if a significant number of our employees are quarantined as a result of exposure to the virus. In addition, actions by our customers and derivative contract counterparties in response to COVID-19 and its economic impacts, including potential non-performance or delays, may also have an adverse impact on our business.
Natural gas and oil prices are expected to continue to be volatile as a result of the ongoing COVID-19 pandemic and other geopolitical factors, and as changes in natural gas and oil inventories, industry demand and national and economic performance are reported, and we cannot predict when prices will improve and stabilize. Due to numerous uncertainties, we cannot at this time predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the natural gas and oil markets will have on our business, financial condition and results of operations.
28

If commodity prices fall or drilling efforts are unsuccessful, we may be required to record write downs of the carrying value of our natural gas and oil properties.
We have been required to write down the carrying value of certain of our natural gas and oil properties in the past, and there is a risk that we will be required to take additional writedowns in the future. Writedowns may occur in the future when natural gas and oil prices are low, or if we have downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs, or due to the anticipated sale of properties.
The successful efforts method of accounting requires that we periodically review the carrying value of our natural gas and oil properties for possible impairment. Impairment is recognized for the excess of book value over fair value when the book value of a proven property is greater than the expected undiscounted future net cash flows from that property and on acreage when conditions indicate the carrying value is not recoverable. We may be required to write down the carrying value of a property based on natural gas and oil prices at the time of the impairment review, or as a result of continuing evaluation of drilling results, production data, economics, divestiture activity, and other factors. A writedown constitutes a non-cash charge to earnings and does not impact cash or cash flows from operating activities; however, it reflects our long-term ability to recover an investment, reduces our reported earnings and increases certain leverage ratios. See Impairments within Critical Accounting Estimates included in Item 7 of this report for further information.
Significant capital expenditures are required to replace our reserves and conduct our business.
Our exploration, development and acquisition activities require substantial capital expenditures. We intend to fund our capital expenditures through cash flows from operations, and to the extent that is not sufficient, borrowings under our revolving credit facility. Our ability to generate operating cash flow is subject to a number of risks and variables, such as the level of production from existing wells, prices of natural gas, oil and NGL, our success in developing and producing new reserves and the other risk factors discussed herein. Our forecasted 2023 capital expenditures, inclusive of capitalized interest, are $1.765 - $1.835 billion compared to our 2022 capital spending level of $1.9 billion. Management continues to review operational plans for 2023 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of natural gas, oil and NGL. If we are unable to fund our capital expenditures as planned, we could experience a curtailment of our exploration and development activity, a loss of properties and a decline in our natural gas, oil and NGL reserves.
If we are not able to replace reserves, we may not be able to sustain production.
Our future success depends largely upon our ability to find, develop or acquire additional natural gas and oil reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Thus, our future natural gas and oil reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.
The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
The estimates of our proved reserves and the estimated future net revenues from our proved reserves included in this report are based upon various assumptions, including assumptions required by the SEC relating to natural gas, oil and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating natural gas, oil and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.
Actual future production, natural gas, oil and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas, oil and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing natural gas and oil prices and other factors, many of which are beyond our control.
29

As of December 31, 2022, approximately 33% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans for capital expenditures to convert PUDs into proved developed reserves, including approximately $4.3 billion during the next five years. You should be aware that the estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated. If we choose not to develop our PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the SEC's reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.
You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average natural gas and oil price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2022 present value is based on prices of $6.36 per mcf of natural gas, $93.67 per bbl of oil and $43.58 per bbl of NGL, before basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
The timing of both the production and the expenses from the development and production of natural gas and oil properties will affect both the timing of future net cash flows from our proved reserves and their present value. Any changes in demand for natural gas and oil, governmental regulations or taxation will also affect the future net cash flows from our production. In addition, the 10% discount factor that is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the gas and oil industry in general will affect the appropriateness of the 10% discount factor.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We have acquired undeveloped properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells.
Drilling for natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, federal restrictions on gas and oil leasing and permitting, and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the areas in which we operate, will be reduced or eliminated if commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for natural gas, oil and NGL, costs associated with producing natural gas, oil and NGL and our ability to add reserves at an acceptable cost.
We rely to a significant extent on seismic data and other technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties, or drilling a well, whether natural gas or oil is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.
30

Certain of our undeveloped properties are subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.
Leases on natural gas and oil properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases on our undeveloped properties expire and we are unable to renew the leases, we will lose our right to develop the related properties. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties.
Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
To manage our exposure to price volatility, we enter into natural gas, oil and NGL price derivative contracts. Our natural gas, oil and NGL derivative arrangements may limit the benefit we would receive from increases in commodity prices. The fair value of our natural gas, oil and NGL derivative instruments can fluctuate significantly between periods. Our decision to mitigate cash flow volatility through derivative arrangements, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to enter into derivatives if we believe the pricing environment for certain time periods is unfavorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program.
Most of our natural gas, oil and NGL derivative contracts are with counterparties under bilateral hedging arrangements. Under a majority of our arrangements, the collateral provided for our obligations is secured by the same hydrocarbon interests that secure our New Credit Facility. Our counterparties’ obligations under the arrangements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us exceed defined thresholds. Collateral requirements are dependent to a large extent on natural gas and oil prices.
Natural gas, oil and NGL derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, the value of our commodity derivative asset positions increase, which increases our counterparty exposure. Although the counterparties to our hedging arrangements are required to secure their obligations to us under certain scenarios, if any of our counterparties were to default on their obligations to us under the derivative contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future cash flows being exposed to commodity price changes.
Natural gas and oil operations are uncertain and involve substantial costs and risks.
Our operating activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive gas or oil reservoirs. Drilling for natural gas, oil and NGL can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop gas and oil properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. Although both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. In addition, our gas and oil properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:
unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
equipment failures or accidents;
fires, explosions, blowouts, cratering or loss of well control;
the mishandling or underground migration of fluids and chemicals;
31

adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures;    
issues with title or in receiving governmental permits or approvals;
restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;
environmental hazards or liabilities;
restrictions in access to, or disposal of, water used or produced in drilling and completion operations;
shortages or delays in the availability of services or delivery of equipment; and
unexpected or unforeseen changes in regulatory policy, and political or public opinion.
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities. Although we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, war, terrorism and piracy, we have limited or no insurance coverage. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant event against which we are not fully insured may expose us to liabilities.
Moreover, certain of these events could result in environmental pollution and impact to third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant damage to property and natural resources.
Our ability to produce natural gas, oil and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Development activities, particularly hydraulic fracturing, require the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. The imposition of environmental initiatives and regulations could further restrict our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of natural gas and oil.
Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.
In certain resource plays, the capacity of gathering and transportation systems is insufficient to accommodate potential production from existing and new wells. We rely heavily on third parties to meet our natural gas, oil and NGL gathering needs. Capital constraints could limit the construction of new pipelines and gathering systems and the provision or expansion of trucking services by third parties. Until this new capacity is available, we may experience delays in producing and selling our natural gas, oil and NGL. In such event, we might have to shut in our wells while awaiting a pipeline connection or additional capacity, which would adversely affect our results of operations.
A portion of our natural gas, oil and NGL production in any region may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow.
32

Cyber-attacks targeting systems and infrastructure used by the gas and oil industry and related regulations may adversely impact our operations and, if we or our third-party providers are unable to obtain and maintain adequate protection for our key systems and data, our business may be harmed.
Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of natural gas, oil and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners. In addition, many third-party providers, such as vendors and others in the supply chain, directly or indirectly provide to us various products and services across an array of internal and external functions that enable us to conduct, monitor and/or protect our business, systems and data assets. In addition, in the ordinary course, we and our service providers collect, process, transmit, and store proprietary and confidential data, including personal information.
We have been the subject of cyber-attacks on our internal systems and through those of third parties in the past. As an energy company, we expect to continue to be a target for such attacks in the future from nation-state sponsored foreign actors and other attackers. We are vulnerable to malicious attacks by third parties or insiders, social engineering and human error, as well as to bugs and other vulnerabilities that may exist in our or our third-party providers’ systems or technologies. Unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. If our information technology systems cease to function properly or our cybersecurity is breached (for example, due to ransomware), we could suffer disruptions to our normal operations, which may include disruptions to our drilling, completion, production and corporate functions. A cyber-attack, or the perception thereof, involving our information systems and related infrastructure, or that of our business associates or third-party providers, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.
Both the frequency and magnitude of cyberattacks is expected to increase and attackers are becoming more sophisticated. As a result, we may be unable to anticipate, detect, prevent, or contain future attacks, particularly as the methodologies utilized by attackers change frequently or are not recognized until launched, and we may be unable to investigate or remediate incidents because attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove or obfuscate forensic evidence. Further, the COVID-19 pandemic has increased our exposure to potential cybersecurity breaches as a result of global remote working dynamics for our customers, employees and third-party providers that present additional risk that threat actors may seek to engage in social engineering (for example, phishing) and to exploit vulnerabilities in corporate and non-corporate networks. As cyber-attacks continue to evolve, we may be required to spend significant additional resources to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks. In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs as we collect and store personal data related to employees, royalty owners and other parties. Any failure to comply with these laws and regulations could result in significant penalties and legal liability. For example, we are subject to various state privacy laws, such as the California Consumer Privacy Act (“CCPA”), which came into effect in January, 2020, and the California Privacy Rights Act (“CPRA”), which expands upon the CCPA and came into effect in January 2023 (with a lookback period until January 2022). The CCPA and the CPRA, among other things, contain new disclosure obligations for businesses that collect personal information about California residents and enhanced consumer protections for those individuals, and provide for statutory fines and penalties for certain data security breaches or other CCPA and CPRA violations. At least fifteen other states have considered, and some have already enacted, privacy laws like the CCPA and the CPRA.
Any losses, costs or liabilities directly or indirectly related to cyberattacks or similar incidents may not be covered by, or may exceed the coverage limits of, any or all of our insurance policies.

33

Our operations could be disrupted by natural or human causes beyond our control.

Our operations are subject to disruption from natural or human causes beyond our control, including risks from extreme weather events, such as hurricanes, severe storms, floods, droughts, heat waves, winter storms, and ambient temperature or precipitation changes, as well as wildfires, war, accidents, civil unrest, political events, earthquakes, system failures, cyber threats, terrorist acts and epidemic or pandemic diseases, such as the COVID-19 pandemic, any of which could result in suspension of operations (including those of our customers or suppliers) or harm to people, our assets or the natural environment.
It is difficult to predict with certainty the timing, frequency or severity of such events or how such frequency or severity may change. Any such events could have a material adverse effect on our results of operations or financial condition. Moreover, any changes in ambient temperatures may impact demand for natural gas if it results in lower energy needs for, among other things, temperature control. While concerns over energy security have, in some situations, seen increased demand for natural gas, sustained concerns over energy security may result in an accelerated adoption of renewable energy and other alternative energy generation or storage, or energy efficiency, technologies. Any such accelerated adoption of alternative energy sources or energy efficiency improvements may decrease demand for our products or otherwise adversely impact our business or results of operations.
In addition, our headquarters are located in Oklahoma City, Oklahoma, an area that experiences severe weather events, including tornadoes and earthquakes. Our information systems and administrative and management processes are primarily provided to our various drilling projects and producing wells throughout the United States from this location, which could be disrupted if a catastrophic event, such as a tornado, power outage or act of terror, destroyed or severely damaged our headquarters. Any such catastrophic event could harm our ability to conduct normal operations and could adversely affect our business.
A deterioration in general economic, political, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.
Historically, concerns about global economic growth and international political stability have had a significant impact on global financial markets and commodity prices, including petroleum products. If the economic or political climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and materially adversely impact our results of operations, liquidity and financial condition. The global market is also currently experiencing inflationary pressure, including rising fuel costs, a tightening steel market and labor and supply chain shortages, which could result in increases to our operating and capital costs that are not fixed.
Military and other armed conflicts, including terrorist activities, and related price volatility and geopolitical instability could materially and adversely affect our business and results of operations.
Military and other armed conflicts, terrorist attacks and the threat of both, whether domestic or foreign, could cause instability in the global financial and energy markets. Continued instability in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices, including petroleum products, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business and results of operations.
For example, in late February 2022, Russia launched a military invasion against Ukraine. Sustained conflict and disruption in the region is likely in the near term, and the longer-term duration of the war is uncertain. The Russian invasion has caused, and could intensify, volatility in natural gas, oil and NGL prices, driving a sharp upward spike in the short term, and may have an impact on global growth prospects, which could in turn affect demand for natural gas and oil. Any such volatility, impacts on demand and disruptions may also magnify the impact of other risk factors described in this report.
34


Financial Risks Related to our Business
We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by industry conditions.
Disruptions in the capital and credit markets, in particular with respect to the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. In the past, low commodity prices have caused and may continue to cause lenders to increase the interest rates under upstream operators’ credit facilities, enact tighter lending standards, refuse to refinance existing debt around maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. Additionally, certain financial institutions have announced their intention to cease investment banking and corporate lending activities in the North American gas and oil sector or have established climate-related funding commitments that could have the effect of limiting their investment in us or our industry. If we are unable to access the capital and credit markets on favorable terms, it could have a material adverse effect on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt. Additionally, challenges in the economy have led and could further lead to reductions in the demand for gas and oil, or further reductions in the prices of gas and oil, or both, which could have a negative impact on our financial position, results of operations and cash flows.
Restrictive covenants in certain of our debt agreements could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Our debt agreements impose operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:
incur additional indebtedness;
make investments or loans;
create liens;
consummate mergers and similar fundamental changes;
make restricted payments;
make investments in unrestricted subsidiaries;
enter into transactions with affiliates; and
use the proceeds of asset sales.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under certain of our debt agreements. The restrictions contained in the covenants could:
limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan; and
adversely affect our ability to finance our operations, enter into acquisitions or divestitures to engage in other business activities that would be in our interest.
Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan and the transactions contemplated thereby.
In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize.
35

Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks, and the assumptions underlying the projections and/or valuation estimates may prove to be incorrect in material respects. Actual results may vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

Legal and Regulatory Risks
We are subject to extensive governmental regulation, which can change and could adversely impact our business.

Our operations are subject to extensive federal, state, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of gas, oil and NGL, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes, and tribal laws for a minor portion of our acreage. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. For example, on January 27, 2021, President Biden issued an executive order indefinitely suspending new natural gas and oil leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal gas and oil permitting and leasing practices. The federal district court in Louisiana issued a permanent injunction against the executive order on August 18, 2022, limited to the thirteen plaintiff states, Louisiana, Alabama, Alaska, Arkansas, Georgia, Mississippi, Missouri, Montana, Nebraska, Oklahoma, Texas, Utah, and West Virginia. In response to the January 27, 2021 executive order, the U.S. Department of the Interior released its “Report On The Federal Oil And Gas Leasing Program” in November 2021, which assessed the current state of gas and oil leasing on federal lands and proposed several reforms, including raising royalty rates and implementing stricter standards for entities seeking to purchase gas and oil leases. Although we do not expect this ruling to impact the availability of onshore federal gas and oil lease sales, the Biden Administration’s increased focus on the climate change impacts of federal projects could result in similar restrictions surrounding onshore drilling, onshore federal lease availability, and restrictions on the ability to obtain required permits, which could have a material adverse impact on our operations. In addition, we may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or orders.

In addition, changes in public policy have affected, and in the future could further affect, our operations. At both the federal and state level, for example, there are an increasing number of legislative initiatives and proposals that may lead to reduced demand for fossil fuels such as oil and gas. These include certain tax advantages and other subsidies to support alternative energy sources or that mandate the use of specific fuels or technologies, in addition to the promotion of research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The IRA, signed by President Biden in August 2022, provides significant funding and incentives for research, development and implementation of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change. The IRA also includes a methane emissions reduction program that amends the Clean Air Act to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. Regulatory developments could, among other things, restrict production levels, impose price controls, change environmental protection requirements with respect to the treatment of hazardous waste, air emissions, or water discharges, and increase taxes, royalties and other amounts payable to the government. Our operating and compliance costs could increase further if existing laws and regulations are revised, reinterpreted, or if new laws and regulations become applicable to our operations. We do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity. This is particularly true of changes related to pipeline safety, hydraulic fracturing and climate change, as discussed below.
Pipeline Safety. The pipeline assets in which we own interests are subject to stringent and complex regulations related to pipeline safety and integrity management. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has established a series of rules that require pipeline operators to develop and implement integrity
36

management programs for gas, NGL and condensate transmission pipelines as well as for certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Recent PHMSA rules have also extended certain requirements for integrity assessments and leak detections beyond high consequence areas and impose a number of reporting and inspection requirements on regulated pipelines. In November 2021, PHMSA issued a final rule that expands certain federal pipeline safety requirements to all onshore gas gathering pipelines, regardless of size or location. The final rule establishes two new types of onshore gas gathering pipelines subject to varying degrees of regulation: all onshore gathering line operators are now subject to PHMSA’s annual reporting and incident reporting requirements, and certain previously unregulated rural gas gathering lines must now comply with PHMSA damage prevention and, depending on the size of the pipeline, construction and operational requirements. The final rule became effective on May 16, 2022. Further, legislation funding PHMSA through 2023 requires the agency to engage in additional rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. At this time, we cannot predict the cost of these requirements or other potential new or amended regulations, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.
Hydraulic Fracturing. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations. State and federal regulatory agencies have also recently focused on a possible connection between the operation of injection wells used for natural gas and oil waste disposal and seismic activity. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.

Climate Change. Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on greenhouse gas emissions. The EPA and the BLM have issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the gas and oil industry and are likely to create additional regulations regarding such matters. For example, on November 15, 2021, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound (VOC) emissions from new and existing operations in the gas and oil sector, including the exploration and production, transmission, processing, and storage segments. The EPA issued a supplemental proposed rule on November 15, 2022 to update, strengthen and expand its November 2021 proposed rule. The supplemental proposed rule would impose more stringent requirements on the natural gas and oil industry. The rule is expected to be finalized in 2023. Additionally, on November 30, 2022, the BLM issued a proposed rule to reduce the methane waste from venting, flaring, and leaks during oil and gas production activities on Federal and Indian leases. Once finalized, these regulations are likely to be subject to legal challenge. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the gas and oil industry remain a significant possibility. In addition, several states in which we operate have imposed limitations designed to reduce methane emissions from gas and oil exploration and production activities. Legislative and state initiatives to date have generally focused on the development of renewable energy standards and/or cap-and-trade and/or carbon tax programs. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time. The development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level could reduce the demand for gas and oil, thereby adversely impacting our earnings, cash flows and financial position. In addition, federal or state carbon taxes or fees could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.
37

In addition, the SEC has issued proposed rules that would mandate extensive disclosure of climate-related risks and other information, including risk management, GHG emissions, financial impacts, and related governance and strategy. In addition to potential costs, these disclosures may be used by some activists for potential litigation or to pressure capital providers to restrict or eliminate investments or other funding. For more information see our risk factor titled “Negative public perception regarding us or our industry could have an adverse effect on our operations.”
These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for gas and oil, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity.
Environmental matters and related costs can be significant.
As an owner, lessee or operator of gas and oil properties, we are subject to various federal, state, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of remediating pollution that results from our operations. Environmental laws may impose strict, joint and several liability, and failure to comply with environmental laws and regulations can result in the imposition of administrative, civil or criminal fines and penalties, as well as injunctions limiting operations in affected areas. Any future costs associated with these matters are uncertain and will be governed by several factors, including future changes to regulatory requirements. Changes in or additions to public policy regarding the protection of the environment could have a significant impact on our operations and profitability.
Increasing attention to ESG matters and our ability to achieve and maintain ESG certifications, goals and commitments may impact our business, financial results or stock price.
In recent years, increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community. Expectations regarding voluntary ESG initiatives and disclosures and consumer demand for more sustainable products, including alternative forms of energy, may result in increased costs (including but not limited to increased costs related to compliance, stakeholder engagement, contracting and insurance), changes in demand for certain products, increased availability of (and competition from) alternative energy sources and technologies, increased development of and demand for products that do not use fossil fuels or their derivatives, enhanced compliance or disclosure obligations, or other adverse impacts to our business, financial condition, or results of operations. Additionally, a number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, activist investors, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change, advocating for changes to companies’ boards of directors, and promoting the use of energy saving building materials. These activities may result in demand shifts for natural gas, oil and NGL in addition to potentially impacting our access to, and costs of, capital.
While we may at times engage in voluntary initiatives (such as voluntary disclosures, certifications, or targets, among others) or commitments to improve our ESG profile and/or products or to respond to stakeholder expectations, such initiatives or achievement of such commitments may be costly and may not have the desired effect. For example, expectations around management of ESG matters continues to evolve rapidly, in many instances due to factors that are out of our control. In addition, we may commit to certain initiatives or goals, and we may not ultimately be able to achieve such commitments or goals, either on the timeframes or costs initially anticipated or at all, due to factors that are within or outside of our control. Moreover, actions or statements that we may take based on expectations, assumptions, or third-party information that we currently believe to be reasonable may subsequently be determined to be erroneous or be subject to misinterpretation. Even if this is not the case, our current actions may subsequently be determined to be insufficient by various stakeholders, and we may be subject to investor or regulator engagement on our ESG initiatives and disclosures, even if such initiatives are currently voluntary. Any failure to comply with investor or customer expectations and standards, which are evolving, or if we are perceived to not have responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, could cause reputational harm to our business, increase our risk of litigation,
38

and could have a material adverse effect on our results of operations. For example, plaintiffs have brought litigation against various companies, including those in the fossil fuel sector, alleging that such companies created public nuisances by producing, handling or marketing fuels that contributed to climate change or that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose those impacts. While we are not currently parties to any such litigation, the ultimate outcomes of such litigation and its impact to us are uncertain; we could incur substantial legal costs associated with defending against these or similar lawsuits in future.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG matters. These ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. To the extent ESG matters negatively affect our reputation, it may also harm our ability to attract or retain employees or customers.
We expect there will likely be increasing levels of regulation, disclosure-related and otherwise, with respect to ESG matters, which will likely lead to increased compliance costs as well as scrutiny that could heighten all of the risks identified in this risk factor. Such ESG matters may also impact our suppliers or customers, which could augment existing, or cause additional, impacts to our business or operations.
The taxation of independent producers is subject to change, and changes in tax law could increase our cost of doing business.
We are subject to taxation by various governmental authorities at the federal, state and local levels in the jurisdictions in which we do business. New legislation could be enacted by any of these governmental authorities making it more costly for us to produce natural gas and oil by increasing our tax burden. The IRA was enacted on August 16, 2022, and includes, among other things, a 15% corporate minimum tax on adjusted financial statement income and a 1% excise tax on stock buybacks. Although we do not believe we will be subject to the corporate minimum tax in 2023, we may become subject to it in future years. Additionally, the Biden administration has called for changes to fiscal and tax policies which could lead to comprehensive tax reform. For example, federal legislation has been proposed that, if enacted, would impact federal income tax law applicable to the deduction of intangible drilling and development costs, percentage depletion and, the expensing of geological, geophysical, exploration and development costs. Other proposals changing federal income tax law could include an increase to the corporate tax rate, an increase to the excise tax on stock buybacks and the elimination of certain tax credits. If enacted, certain of these proposals could have a correlative impact on state income taxes. In addition, state and local authorities could enact new legislation that would increase various taxes such as sales, severance and ad valorem taxes as well as accelerate the collection of such taxes.
Trading in our New Common Stock, additional issuances of New Common Stock, and certain other stock transactions could lead to a second, potentially more restrictive annual limitation on the utilization of our tax attributes reducing their ability to offset future taxable income, which may result in an increase to income tax liabilities.
Upon emergence from bankruptcy on February 9, 2021, the Company experienced an ownership change under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), as all of the common stock and preferred stock of the Predecessor, or the old loss corporation, was canceled and replaced with New Common Stock of the Successor, or the new loss corporation (the “First Ownership Change”). As such, an annual limitation was computed based on the fair market value of the new equity immediately after emergence multiplied by the long-term tax-exempt rate in effect for the month of February 2021. This annual limitation will restrict the future utilization of our net operating loss (NOL) carryforwards, disallowed business interest carryforwards and tax credits that existed at the time of emergence.
Trading in our stock, additional issuances, and other stock transactions occurring subsequent to the emergence from Bankruptcy could lead to a second ownership change. In the event of a second ownership change, a second annual limitation would be determined at such time which could be more restrictive than the limitation of the First Ownership Change. Depending on the market conditions and the Company’s tax basis, a second ownership change may result in a net unrealized built-in loss.
39

The annual limitation in such a case would additionally be applied to certain of the Company’s tax items other than just NOL carryforwards, disallowed business interest carryforwards and tax credits. For example, a portion of tax depreciation, depletion and amortization would also be subject to the annual limitation for a five-year period following the ownership change but only to the extent of the net unrealized built-in loss existing at the time of the second ownership change. Whether the new annual limitation would be more restrictive would depend on the value of our stock and the long-term tax-exempt rate in effect at the time of a second ownership change. If the new annual limitation is more restrictive it would apply to certain of the tax attributes existing at the time of the second ownership change including those remaining from the time of the First Ownership Change.
Some states impose similar limitations on tax attribute utilization upon experiencing an ownership change.
Item 1B.Unresolved Staff Comments
Not applicable.
Item 2.Properties
Information regarding our properties is included in Item 1. Business and in the Supplementary Information included in Item 8 of Part II of this report.

Item 3.Legal Proceedings
Chapter 11 Proceedings
Commencement of the Chapter 11 Cases automatically stayed the proceedings and actions against us that are referenced below, in addition to actions seeking to collect pre-petition indebtedness or to exercise control over the property of the Company’s bankruptcy estates. The Plan in the Chapter 11 Cases, which became effective on February 9, 2021, provided for the treatment of claims against the Company’s bankruptcy estates, including pre-petition liabilities that had not been satisfied or addressed during the Chapter 11 Cases. See Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for additional information.
Litigation and Regulatory Proceedings
We were involved in a number of litigation and regulatory proceedings as of the Petition Date. Many of these proceedings were in early stages, and many of them sought damages and penalties, the amount of which is currently indeterminate. See Note 7 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings.
Business Operations. We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. The majority of these prepetition legal proceedings were settled during the Chapter 11 Cases or will be resolved in connection with the claims reconciliation process before the Bankruptcy Court. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan.
Environmental Contingencies
The nature of the natural gas and oil business carries with it certain environmental risks for us and our subsidiaries. We have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. We conduct periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, we may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.
40

Other Matters
Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to our business operations is likely to have a material adverse effect on our future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
Item 4.Mine Safety Disclosures
The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17CFR 229.104) is included in Exhibit 95.1 to this Form 10-K.
41

PART II
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
Upon our emergence from Chapter 11 bankruptcy on February 9, 2021, our then-authorized common stock and preferred stock were canceled and released under the Plan without receiving any recovery on account thereof. In accordance with the Plan confirmed by the Bankruptcy Court on February 9, 2021, we issued 97,097,081 shares of New Common Stock of the Successor, which are listed on the Nasdaq Stock Market LLC under the symbol CHK. In addition, on February 9, 2021, we issued 11,111,111 Class A Warrants, 12,345,679 Class B Warrants and 9,768,527 Class C Warrants, each of which are exercisable for one share of common stock per warrant at the initial exercise prices of $27.63, $32.13 and $36.18 per share, respectively. The warrants are immediately exercisable and will expire on February 9, 2026. For more information regarding our emergence from Chapter 11 bankruptcy and our Plan of Reorganization, see Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report. Additionally, more information on our New Common Stock and Warrants can be found in Note 12 of the notes to our consolidated financial statements included in Item 8 of Part II of this report.
Dividends
We declared the first quarterly dividend on our New Common Stock in the second quarter of 2021, which consisted of a base dividend per share. In March 2022, we adopted a variable return program that resulted in the payment of an additional variable dividend equal to the sum of Adjusted Free Cash Flow from the prior quarter less the base quarterly dividend, multiplied by 50%. The declaration and payment of any future dividend is subject to the approval of our Board of Directors in its discretion. Since the initial base dividend declared during the second quarter of 2021, we have incrementally increased the base dividend per share. For additional information on our dividends, see Note 12 of the notes to our consolidated financial statements included in Item 8 of Part II of this report.
42


Repurchases of Equity Securities; Unregistered Sales of Equity Securities and Use of Proceeds
On December 2, 2021, we announced that our Board of Directors authorized the repurchase of up to $1.0 billion in aggregate value of our common stock and/or warrants from time to time. In June 2022, our Board of Directors authorized an increase in the size of the share repurchase program from $1.0 billion to $2.0 billion in aggregate value of our common stock and/or warrants. The repurchase authorization permits repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, compliance with the Company’s debt agreements and other appropriate factors. The share repurchase program expires on December 31, 2023. The following table provides information regarding purchases of our common stock made by us during the quarter ended December 31, 2022. In 2023, our share repurchase program will be subject to a 1% excise tax imposed under the Inflation Reduction Act of 2022.
PeriodTotal Number of Shares PurchasedAverage Price Paid Per ShareTotal Number of Shares Purchased as Part of Publicly Announced Plans or ProgramsApproximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions)
October 1 - October 314,033,368 $98.90 4,033,368 $934 
November 1 - November 3072,083 $99.09 72,083 $927 
December 1 - December 31— $— — $927 
Total4,105,451 $98.90 4,105,451 
Stockholders
As of February 16, 2023, there were approximately 154 holders of record of our common stock.
Item 6.Reserved

43


Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to provide a reader of our financial statements with management’s perspective on our financial condition, liquidity, results of operations and certain other factors that may affect our future results. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with Item 8 of Part II of this report.
Introduction
We are an independent exploration and production company engaged in the acquisition, exploration and development of properties to produce natural gas, oil and NGL from underground reservoirs. We own a large portfolio of onshore U.S. unconventional natural gas and liquids assets, including interests in approximately 8,400 natural gas and oil wells as of December 31, 2022. Our natural gas resource plays are the Marcellus Shale in the northern Appalachian Basin in Pennsylvania (“Marcellus”) and the Haynesville/Bossier Shales in northwestern Louisiana (“Haynesville”). Our liquids-rich resource play is in the Eagle Ford Shale in South Texas (“Eagle Ford”). In August 2022, we announced that we viewed the assets in Eagle Ford as non-core to our future capital allocation strategy, and in January 2023, we entered into an agreement to sell a portion of our Eagle Ford assets to WildFire Energy I LLC for $1.425 billion. Additionally, in February 2023, we entered into an agreement to sell a portion of our remaining Eagle Ford assets to INEOS Energy for $1.4 billion.
Our strategy is to create shareholder value through the responsible development of our significant resource plays while continuing to be a leading provider of affordable, reliable, low carbon energy to the United States. We continue to focus on improving margins through operating efficiencies and financial discipline and improving our ESG performance. To accomplish these goals, we intend to allocate our human resources and capital expenditures to projects we believe offer the highest cash return on capital invested, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities to strengthen our portfolio. We also intend to continue to dedicate capital to projects that reduce the environmental impact of our natural gas and oil producing activities. We continue to seek opportunities to reduce cash costs (production, gathering, processing and transportation and general and administrative), through operational efficiencies and improving our production volumes from existing wells.
Leading a responsible energy future is foundational to Chesapeake's success. Our core values and culture demand we continuously evaluate the environmental impact of our operations and work diligently to improve our ESG performance across all facets of our Company. Our path to answering the call for affordable, reliable, low carbon energy begins with our goal to achieve net zero greenhouse gas emissions (Scope 1 and 2) by 2035. To meet this challenge, we have set meaningful goals including:
Eliminate routine flaring from all new wells completed from 2021 forward, and enterprise-wide by 2025;
Reduce our methane intensity to 0.02% by 2025 (achieved approximately 0.05% in 2022); and
Reduce our GHG intensity to 3.0 metric tons CO2 equivalent per thousand barrel of oil equivalent by 2025 (achieved approximately 3.9 in 2022).
In July 2021, we announced our plan to receive independent certification of our natural gas production under the MiQ methane standard and EO100™ Standard for Responsible Energy Development. As of December 31, 2022, we have received certification for all our operated gas assets in Haynesville and Marcellus as responsibly sourced gas. The MiQ certification provides a verified approach to tracking our commitment to reduce our methane intensity, as well as support our overall objective of achieving net-zero Scope 1 and 2 greenhouse gas emissions by 2035.
44

Our results of operations as reported in our consolidated financial statements for the 2022 Successor Period, 2021 Successor Period, 2021 Predecessor Period and 2020 Predecessor Period are in accordance with GAAP. Although GAAP requires that we report on our results for the periods January 1, 2021 through February 9, 2021 and February 10, 2021 through December 31, 2021 separately, management views our operating results for the year ended December 31, 2021 by combining the results of the 2021 Predecessor Period and the 2021 Successor Period because management believes such presentation provides the most meaningful comparison of our results to prior periods. We are not able to compare the 40 days from January 1, 2021 through February 9, 2021 operating results to any of the previous periods reported in the consolidated financial statements and do not believe reviewing this period in isolation would be useful in identifying any trends in, or reaching any conclusions regarding, our overall operating performance. We believe the key performance indicators, such as operating revenues and expenses for the 2021 Successor Period combined with the 2021 Predecessor Period, provide more meaningful comparisons to other periods and are useful in understanding operational trends. Additionally, there were no changes in policies between the periods, and any material impacts as a result of fresh start accounting were included within the discussion of these changes. These combined results do not comply with GAAP and have not been prepared as pro forma results under applicable regulations, but are presented because we believe they provide the most meaningful comparison of our results to prior periods.
Recent Developments
Acquisitions
On March 9, 2022, we completed our Marcellus Acquisition pursuant to definitive agreements with Chief, Radler and Tug Hill, Inc. dated January 24, 2022. On November 1, 2021, we completed our Vine Acquisition pursuant to a definitive agreement with Vine dated August 10, 2021. These transactions strengthen Chesapeake’s competitive position, meaningfully increasing our operating cash flows and adding high quality producing assets and a deep inventory of premium drilling locations, while preserving the strength of our balance sheet.
Divestitures
On March 25, 2022, we completed the sale of our Powder River Basin assets in Wyoming to Continental Resources, Inc. for $450 million in cash, subject to post-closing adjustments, which resulted in the recognition of a gain of approximately $293 million.
On January 17, 2023, we entered into an agreement to sell a portion of our Eagle Ford assets to WildFire Energy I LLC for $1.425 billion. This transaction, which is subject to certain customary closing conditions, including certain regulatory approvals, is expected to close in the first quarter of 2023. As of December 31, 2022, the assets and liabilities associated with this transaction were classified as held for sale.
On February 17, 2023 we entered into an agreement to sell a portion of our remaining Eagle Ford assets to INEOS Energy for $1.4 billion. This transaction, which is subject to certain customary closing conditions, including certain regulatory approvals, is expected to close in the second quarter of 2023.
Investments - Momentum Sustainable Ventures LLC
During the fourth quarter of 2022, we entered into an agreement with Momentum Sustainable Ventures LLC to build a new natural gas gathering pipeline and carbon capture and sequestration project, which will gather natural gas produced in the Haynesville Shale for re-delivery to Gulf Coast markets, including LNG export. The pipeline is expected to have an initial capacity of 1.7 Bcf/d expandable to 2.2 Bcf/d. The carbon capture portion of the project anticipates capturing and permanently sequestering up to 2.0 million tons per annum of CO2. The natural gas gathering pipeline in-service is projected for the fourth quarter of 2024, and the carbon sequestration portion of the project is subject to regulatory approvals. As of December 31, 2022, we have made capital contributions of $18 million to the project.
45

New Credit Facility
On December 9, 2022, we entered into a new senior secured reserve-based revolving credit agreement providing for the New Credit Facility, which features an initial borrowing base of $3.5 billion and aggregate commitments of $2.0 billion. The New Credit Facility includes terms that change favorably upon us receiving and maintaining investment grade ratings by S&P, Moody’s and/or Fitch and the satisfaction of certain other conditions. The New Credit Facility matures in December 2027.
Repurchases of Equity Securities and Dividends
In June 2022, our Board of Directors authorized an increase in the size of our share repurchase program from $1.0 billion to up to $2.0 billion in aggregate value of our common stock and/or warrants. During 2022, we repurchased approximately 11.7 million shares of our common stock pursuant to the share repurchase program and had $927 million available under the share repurchase program as of December 31, 2022. In addition, we have paid dividends of approximately $1.2 billion, in aggregate, on our common stock during 2022. In August 2022, we increased our quarterly base dividend by 10% to $0.55 per share beginning with the dividend that was paid on September 1, 2022.
Warrant Exchange Offer
In August 2022, we announced exchange offers relating to our outstanding Class A Warrants, Class B Warrants, and Class C Warrants. The exchange offers expired in October 2022 and resulted in the issuance of 16,305,984 shares of our common stock in exchange for the cancellation of (i) 4,752,207 Class A Warrants, or approximately 51.4% of the outstanding Class A Warrants, at the time of exchange, (ii) 7,879,030 Class B Warrants, or approximately 64.1% of the outstanding Class B Warrants, at the time of exchange, and (iii) 7,252,004 Class C Warrants, or approximately 64.8% of the outstanding Class C Warrants, at the time of exchange.
COVID-19 Pandemic and Impact on Global Demand for Natural Gas and Oil
The global spread of COVID-19 created significant volatility, uncertainty, and economic disruption commencing in 2020, and threatens to continue to do so in 2023. The ongoing pandemic has resulted in widespread adverse impacts on the global economy and on our customers and other parties with whom we have business relations. To date, we have experienced limited operational impacts as a result of COVID-19 or related governmental restrictions. While we cannot predict the full impact that COVID-19 and its variants, or the related significant disruption and volatility in the natural gas and oil markets will have on our business, cash flows, liquidity, financial condition and results of operations, we believe our cost structure and liquidity position us well to address continued price and demand volatility. For additional discussion regarding risks associated with the COVID-19 pandemic, see Item 1A Risk Factors in this report.
Russia’s Invasion of Ukraine; Volatility in Natural Gas, Oil and NGL Prices; and Inflationary Cost Pressures

In late February 2022, Russia launched a military invasion against Ukraine. The Russian invasion has caused, and could intensify, volatility in natural gas, oil and NGL prices, and may have an impact on global growth prospects, which could in turn affect demand for natural gas and oil. This overall uncertainty resulted in stronger commodity prices during much of 2022. Toward the end of 2022, markets began to stabilize, and this, coupled with a milder winter, has resulted in an observed decline in pricing in early 2023. Our 2023 estimated cash flow is partially protected from commodity price volatility due to our current hedge positions that cover approximately 56% of our projected natural gas volumes for 2023. In addition to the recent weakening in commodity prices, the industry is experiencing inflationary pressure, including rising fuel costs, a tightening steel market, and labor and supply chain shortages, which could result in increases to our operating and capital costs that are not fixed. We continue to monitor the situation and assess its impact on our business, including our business partners and customers, as we work to limit our supply chain risk.
46


Liquidity and Capital Resources
Liquidity Overview
For the 2022 Successor Period, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and borrowings under our credit agreements, and our primary uses of cash have been for the development of our natural gas and oil properties, acquisitions of additional natural gas properties and return of value to stockholders through dividends and equity repurchases. Historically, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, borrowings under certain credit agreements and dispositions of non-core assets. Our ability to issue additional indebtedness, dispose of assets or access the capital markets was substantially limited during the Chapter 11 Cases and required court approval in most instances. Accordingly, our liquidity in the 2021 and 2020 Predecessor Periods depended mainly on cash generated from operations and available funds under certain credit agreements including the DIP Facility in the 2021 Predecessor Period and revolving credit facility in the 2020 Predecessor Period.
We believe we have emerged from the Chapter 11 Cases as a fundamentally stronger company, built to generate sustainable Free Cash Flow with a strengthened balance sheet, large portfolio of onshore U.S. unconventional natural gas and liquids assets and improving ESG performance. As a result of the Chapter 11 Cases, we reduced our total indebtedness by $9.4 billion by issuing equity in a reorganized entity to the holders of our FLLO Term Loan, Second Lien Notes, unsecured notes and allowed general unsecured claimants.
In December 2022, we entered into a New Credit Facility and terminated the Exit Credit Facility, repaying all amounts outstanding and extinguishing all commitments thereunder. We believe our cash flow from operations, cash on hand and borrowing capacity under the New Credit Facility, as discussed below, will provide sufficient liquidity during the next 12 months and the foreseeable future. As of December 31, 2022, we had $1.0 billion of liquidity available, including $130 million of cash on hand and $0.9 billion of aggregate unused borrowing capacity available under the New Credit Facility. As of December 31, 2022, we had $1.05 billion of outstanding borrowings under our New Credit Facility and $35 million utilized for various letters of credit. See Note 6 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.
Dividends
We declared the first quarterly dividend on our New Common Stock in the second quarter of 2021, which consisted of a base dividend per share. In March 2022, we adopted a variable return program that resulted in the payment of an additional variable dividend per share equal to the sum of the Adjusted Free Cash Flow from the prior quarter less the base quarterly dividend, multiplied by 50%. Under this base and variable dividend approach, we paid dividends of $1.2 billion, in aggregate, on our common stock in the 2022 Successor Period. See Note 12 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion.
The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of the Board and will depend on the Company’s financial results, cash requirements, future prospects and other relevant factors. The Company’s ability to pay dividends to its stockholders is restricted by (i) Oklahoma corporate law, (ii) its Certificate of Incorporation, (iii) the terms and provisions of the credit agreement governing its New Credit Facility and (iv) the terms and provisions of the indentures governing its 5.50% Senior Notes due 2026, 5.875% Senior Notes due 2029 and 6.75% Senior Notes due 2029.
47

Derivative and Hedging Activities
Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. We enter into various derivative instruments to mitigate a portion of our exposure to commodity price declines, but these transactions may also limit our cash flows in periods of rising commodity prices. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to better predict the total revenue we expect to receive. See Item 7A Quantitative and Qualitative Disclosures About Market Risk included in Part II of this report for further discussion on the impact of commodity price risk on our financial position.
Contractual Obligations and Off-Balance Sheet Arrangements
As of December 31, 2022, our material contractual obligations include repayment of senior notes, outstanding borrowings and interest payment obligations under the New Credit Facility, derivative obligations, asset retirement obligations, lease obligations, capital commitments relating to our investments, undrawn letters of credit and various other commitments we enter into in the ordinary course of business that could result in future cash obligations. In addition, we have contractual commitments with midstream companies and pipeline carriers for future gathering, processing and transportation of natural gas, oil and NGL to move certain of our production to market. The estimated gross undiscounted future commitments under these agreements were approximately $4.3 billion as of December 31, 2022. As discussed above, we believe our existing sources of liquidity will be sufficient to fund our near and long-term contractual obligations. See Notes 6, 7, 9, 15, 18 and 22 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion.
New Credit Facility
On December 9, 2022, the Company, as borrower, entered into a senior secured reserve-based credit agreement providing for the New Credit Facility which features an initial borrowing base of $3.5 billion and aggregate commitments of $2.0 billion. Subject to certain exceptions, the borrowing base will be redetermined semi-annually on or around April 15 and October 15 of each year. The New Credit Facility provides for a $200 million sublimit available for the issuance of letters of credit and a $50 million sublimit available for swingline loans. Borrowings under the credit agreement may be alternate base rate loans or term SOFR loans, at the Company’s election. The New Credit Facility contains certain features that, upon receipt and maintenance of investment grade ratings from S&P, Moody’s and/or Fitch and the satisfaction of certain other conditions, result in the removal or relaxation of specified negative and financial covenants, among other favorable adjustments. See Note 6 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion.
Post-Emergence Debt
On the Effective Date, pursuant to the terms of the Plan, the Company, as borrower, entered into a reserve-based credit agreement providing for the Exit Credit Facility which featured an initial borrowing base of $2.5 billion. The aggregate initial elected commitments of the lenders under the Exit Credit Facility were $1.75 billion of revolving Tranche A Loans and $221 million of fully funded Tranche B Loans.
The Exit Credit Facility provided for a $200 million sublimit of the aggregate commitments that were available for the issuance of letters of credit. The Exit Credit Facility bore interest at the ABR (alternate base rate) or LIBOR, at our election, plus an applicable margin (ranging from 2.25–3.25% per annum for ABR loans and 3.25–4.25% per annum for LIBOR loans, subject to a 1.00% LIBOR floor), depending on the percentage of the borrowing base then being utilized. The Tranche A Loans were due to mature 3 years after the Effective Date and the Tranche B Loans were due to mature 4 years after the Effective Date. In December 2022, in conjunction with our entry into the New Credit Facility, the Exit Credit Facility was terminated, repaying all amounts outstanding and extinguishing all commitments thereunder.
On February 2, 2021, the Company issued $500 million aggregate principal amount of its 5.50% Senior Notes due 2026 (the “2026 Notes”) and $500 million aggregate principal amount of its 5.875% Senior Notes due 2029 (the “2029 Notes” and, together with the 2026 Notes, the “Notes”). The offering of the Notes was part of a series of exit financing transactions undertaken in connection with the Debtors’ Chapter 11 Cases and meant to provide the exit financing originally intended to be provided by the Exit Term Loan Facility pursuant to the Commitment Letter.

48

Assumption and Repayment of Vine Debt
In conjunction with the Vine Acquisition, Vine’s Second Lien Term Loan was repaid and terminated for $163 million inclusive of a $13 million make whole premium with cash on hand, due to the agreement containing a change in control provision making the term loan callable upon closing. Vine’s reserve-based loan facility, which had no borrowings as of November 1, 2021, was terminated at the time of the completion of the Vine Acquisition. Additionally, Vine’s 6.75% Senior Notes with a principal amount of $950 million, were assumed by the Company at the time of the completion of the Vine Acquisition.
Capital Expenditures
For the year ending December 31, 2023, we currently expect to bring or have online approximately 145 to 165 gross wells across 10 to 12 rigs and plan to invest between approximately $1.765 – $1.835 billion in capital expenditures. We expect that approximately 85% of our 2023 capital expenditures will be directed toward our natural gas assets. We currently plan to fund our 2023 capital program through cash on hand, expected cash flow from our operations and borrowings under our New Credit Facility. We may alter or change our plans with respect to our capital program and expected capital expenditures based on developments in our business, our financial position, our industry or any of the markets in which we operate.

49

Sources and (Uses) of Cash and Cash Equivalents
The following table presents the sources and uses of our cash and cash equivalents for the periods presented:
SuccessorPredecessor
 Year Ended
December 31, 2022
Period from February 10, 2021 through
December 31, 2021
Period from January 1, 2021 through February 9, 2021Year Ended December 31, 2020
Cash provided by (used in) operating activities$4,125 $1,809 $(21)$1,164 
Proceeds from New Credit Facility, net1,050 — — — 
Proceeds from issuance of senior notes, net— — 1,000 — 
Proceeds from issuance of common stock— — 600 — 
Proceeds from warrant exercise27 — — 
Proceeds from divestitures of property
  and equipment
407 13 — 150 
Proceeds from pre-petition revolving credit
  facility borrowings, net
— — — 339 
Capital expenditures(1,823)(669)(66)(1,142)
Business combination, net(1,967)(194)— — 
Contributions to investments(18)— — — 
Payments on Exit Credit Facility, net(221)(50)(479)— 
Payments on DIP Facility borrowings— — (1,179)— 
Debt issuance and other financing costs(17)(3)(8)(109)
Cash paid to purchase debt— — — (94)
Cash paid for common stock dividends(1,212)(119)— — 
Cash paid for preferred stock dividends— — — (22)
Cash paid to repurchase and retire common stock(1,073)— — — 
Other— (1)— (13)
Net increase (decrease) in cash, cash equivalents and restricted cash$(722)$788 $(153)$273 
Cash Flow from Operating Activities
Cash provided by operating activities was $4.12 billion, $1.81 billion and $1.16 billion in the 2022 Successor Period, 2021 Successor Period and 2020 Predecessor Period, respectively. Cash used in operating activities was $21 million for the 2021 Predecessor Period. The increase in the 2022 Successor Period is primarily due to higher prices for the natural gas, oil and NGL we sold and increased volumes sold due to the Vine Acquisition and Marcellus Acquisition. The increase in the 2021 Successor Period is primarily the result of higher prices for the natural gas, oil and NGL we sold, coupled with a decrease in cash interest and GP&T costs following our emergence from bankruptcy. The cash used in the 2021 Predecessor Period was primarily in connection with the payment of professional fees related to the Chapter 11 Cases. Cash flows from operations are largely affected by the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and amortization, certain impairments, gains or losses on sales of assets, deferred income taxes and mark-to-market changes in our open derivative instruments. See further discussion below under Results of Operations.
Proceeds from New Credit Facility, net
In the 2022 Successor Period, we borrowed a net $1.05 billion under the New Credit Facility. We utilized these borrowings to terminate the Exit Credit Facility, including the repayment of outstanding Tranche A Loans and Tranche B Loans thereunder, backstopping certain letters of credit, and the payment of fees and expenses in connection with the termination of the Exit Credit Facility and entry into the New Credit Facility. A portion of the borrowings under the New Credit Facility were repaid with internally generated cash provided by operating activities.
50

Proceeds from Issuance of Common Stock and Senior Notes
In the 2021 Predecessor Period, we issued $500 million aggregate principal amount of 5.50% 2026 Notes and $500 million aggregate principal amount of 5.875% 2029 Notes for total proceeds of $1.0 billion. Additionally, upon emergence from Chapter 11, we issued 62,927,320 shares of New Common Stock in exchange for $600 million of cash, as agreed upon in the Plan. See Note 6 and Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion.
Divestitures of Property and Equipment
In the 2022 Successor Period, we sold our Powder River Basin assets to Continental Resources, Inc. for approximately $450 million, subject to post-close adjustments. In the 2021 Successor Period, we divested certain non-core assets for approximately $13 million. In the 2020 Predecessor Period, we divested our Mid-Continent asset for $130 million and certain non-core assets for approximately $6 million. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion.
Capital Expenditures
Our capital expenditures significantly increased in the 2022 Successor Period compared to the combined 2021 Successor and Predecessor Periods primarily as a result of increased drilling and completion activity in Haynesville and Marcellus, following the Vine Acquisition and Marcellus Acquisition, respectively. Our capital expenditures decreased in the combined 2021 Successor and Predecessor Periods compared to the 2020 Predecessor Period primarily as a result of decreased drilling and completion activity mainly in our liquids-rich plays. In the 2022 Successor Period, our average operated rig count was 14 rigs and 217 spud wells, compared to an average operated rig count of 7 rigs and 121 spud wells in the combined 2021 Successor and Predecessor Periods and 8 rigs and 167 spud wells in the 2020 Predecessor Period. We completed 216 operated wells in the 2022 Successor Period compared to 127 in the combined 2021 Successor and Predecessor Periods and 188 in the 2020 Predecessor Period.
Business Combination, net
In the 2022 Successor Period, we completed the Marcellus Acquisition for approximately $2 billion and 9.4 million shares of our common stock. In the 2021 Successor Period, we acquired Vine for approximately 18.7 million shares of our New Common Stock and $253 million cash, less $59 million of cash held by Vine as of the acquisition date. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of these acquisitions.
Contributions to Investments
During the 2022 Successor Period, we made an initial contribution of $18 million to our investment with Momentum Sustainable Ventures LLC to build a new natural gas gathering pipeline and carbon capture project. See Note 18 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for additional information.

Payments on Exit Credit Facility, net
In December 2022, we entered into the New Credit Facility and terminated the Exit Credit Facility, repaying all amounts outstanding and extinguishing all commitments thereunder.

Payments on DIP Facility Borrowings
On the Effective Date, the DIP Facility was terminated, and the holders of obligations under the DIP Facility received payment in full in cash; provided that to the extent such lender under the DIP Facility was also a lender under the Exit Credit Facility, such lender’s allowed DIP claims were first reduced dollar-for-dollar and satisfied by the amount of its Exit RBL Loans provided as of the Effective Date.
51

Debt Issuance and Other Financing Costs
During the 2022 Successor Period, we paid $17 million of one-time fees to lenders to establish the New Credit Facility. In the 2020 Predecessor Period, we paid $109 million of one-time fees to lenders to establish our DIP Credit Facility and Exit Credit Facility.
Cash Paid to Purchase Debt
In the 2020 Predecessor Period, we repurchased approximately $160 million aggregate principal amount of our senior notes for $94 million.
Cash Paid for Common Stock Dividends
As part of our dividend program, we paid common stock base dividends of $256 million and common stock variable dividends of $956 million in the 2022 Successor Period. During the 2021 Successor Period, we paid common stock base dividends of $119 million. See Note 12 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion.
Cash Paid for Preferred Stock Dividends
We paid dividends of $22 million on our Predecessor preferred stock during the 2020 Predecessor Period. On April 17, 2020, we announced that we were suspending payment of dividends on each series of our outstanding convertible preferred stock. On the Effective Date of the Chapter 11 Cases, each holder of an equity interest in the Predecessor had such interest canceled, released, and extinguished without any distribution. See Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for additional information about the Chapter 11 Cases.
Cash Paid to Repurchase and Retire Common Stock
In March 2022, we commenced our share repurchase program, and throughout the 2022 Successor Period, we repurchased 11.7 million shares of our common stock for an aggregate price of $1.1 billion. The shares of common stock that were repurchased during the 2022 Successor Period were retired and recorded as a reduction to common stock and retained earnings.
52


Results of Operations
Year ended December 31, 2022 compared to the year ended December 31, 2021
Below is a discussion of changes in our results of operations for the 2022 Successor Period compared to the combined 2021 Successor and Predecessor Periods. A discussion of changes in our results of operations for the combined 2021 Successor and Predecessor Periods compared to the 2020 Predecessor Period has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2021 as filed with the SEC on February 24, 2022.
Natural Gas, Oil and NGL Production and Average Sales Prices
Successor
Year Ended December 31, 2022
Natural GasOilNGLTotal
MMcf per day$/McfMBbl per day$/BblMBbl per day$/BblMMcfe per day$/Mcfe
Marcellus1,836 6.03 — — — — 1,836 6.03 
Haynesville1,611 5.92 — — — — 1,611 5.92 
Eagle Ford127 5.64 51 96.10 16 36.76 529 11.76 
Powder River Basin10 5.45 95.18 53.96 26 10.66 
Total3,584 5.96 53 96.07 17 37.48 4,002 6.77 
Average NYMEX Price6.64 94.23 
Average Realized Price
  (including realized derivatives)
3.67 66.36 37.48 4.32 
Successor
Period from February 10, 2021 through December 31, 2021
Natural GasOilNGLTotal
MMcf per day$/McfMBbl per day$/BblMBbl per day$/BblMMcfe per day$/Mcfe
Marcellus1,296 3.25 — — — —