0000000000000001326089--12-312020FYfalseNoNoYesYes68764226875672P3Yus-gaap:OperatingLeaseRightOfUseAssetus-gaap:PropertyPlantAndEquipmentAndFinanceLeaseRightOfUseAssetAfterAccumulatedDepreciationAndAmortizationus-gaap:OperatingLeaseLiabilityCurrentus-gaap:OperatingLeaseLiabilityNoncurrentus-gaap:AccruedLiabilitiesCurrentus-gaap:OtherLiabilitiesNoncurrentP1Y19000000001326089us-gaap:RevolvingCreditFacilityMember2020-01-012020-12-310001326089us-gaap:CommonStockMember2020-01-012020-12-310001326089us-gaap:CommonStockMember2019-01-012019-12-3100013260892019-11-012019-11-300001326089us-gaap:RetainedEarningsMember2020-12-310001326089us-gaap:AdditionalPaidInCapitalMember2020-12-310001326089us-gaap:AccumulatedOtherComprehensiveIncomeMember2020-12-310001326089us-gaap:RetainedEarningsMember2019-12-310001326089us-gaap:AdditionalPaidInCapitalMember2019-12-310001326089us-gaap:AccumulatedOtherComprehensiveIncomeMember2019-12-310001326089us-gaap:RetainedEarningsMember2018-12-310001326089us-gaap:AdditionalPaidInCapitalMember2018-12-310001326089us-gaap:AccumulatedOtherComprehensiveIncomeMember2018-12-310001326089us-gaap:CommonStockMember2020-12-310001326089us-gaap:CommonStockMember2019-12-310001326089us-gaap:CommonStockMember2018-12-310001326089snde:AwardDateTwelveMemberus-gaap:RestrictedStockUnitsRSUMember2020-01-012020-12-310001326089snde:AwardDateThirteenMemberus-gaap:RestrictedStockUnitsRSUMember2020-01-012020-12-310001326089snde:AwardDateTwelveMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:AwardDateThirteenMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:AwardDateSixMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:AwardDateNineMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:AwardDateFourteenMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:AwardDateFiveMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:AwardDateFifteenMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:AwardDateElevenMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:AwardDateEightMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089us-gaap:RestrictedStockUnitsRSUMember2018-12-310001326089snde:EquityIncentivePlan2020Member2020-07-012020-12-310001326089snde:VestingConditionsScenarioTwoMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:VestingConditionsScenarioThreeMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:VestingConditionsScenarioSixMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:VestingConditionsScenarioFourMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:VestingConditionsScenarioFiveMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:VestingBasedOn3YearTsrGrantDateMay52019Memberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:VestingBasedOn3YearTsrGrantDateMay312019Memberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089us-gaap:RestrictedStockUnitsRSUMember2020-01-012020-12-310001326089snde:MarketBasedOrPerformanceBasedVestingConditionsNotSatisfiedMember2020-01-012020-12-310001326089snde:EmployeeTerminationsMember2020-01-012020-12-310001326089us-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:MarketBasedOrPerformanceBasedVestingConditionsNotSatisfiedMember2019-01-012019-12-310001326089snde:EmployeeTerminationsMember2019-01-012019-12-310001326089srt:MinimumMembersnde:VestingConditionsScenarioTwoMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089srt:MinimumMembersnde:VestingConditionsScenarioThreeMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089srt:MinimumMembersnde:VestingConditionsScenarioFourMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089srt:MinimumMembersnde:VestingConditionsScenarioFiveMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089srt:MinimumMembersnde:VestingBasedOn3YearTsrGrantDateMay52019Memberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089srt:MinimumMembersnde:VestingBasedOn3YearTsrGrantDateMay312019Memberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089srt:MaximumMembersnde:VestingConditionsScenarioTwoMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089srt:MaximumMembersnde:VestingConditionsScenarioThreeMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089srt:MaximumMembersnde:VestingConditionsScenarioFourMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089srt:MaximumMembersnde:VestingConditionsScenarioFiveMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089srt:MaximumMembersnde:VestingBasedOn3YearTsrGrantDateMay52019Memberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089srt:MaximumMembersnde:VestingBasedOn3YearTsrGrantDateMay312019Memberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:AwardDateTenMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089snde:AwardDateSevenMemberus-gaap:RestrictedStockUnitsRSUMember2019-01-012019-12-310001326089us-gaap:OilAndCondensateMember2020-01-012020-12-310001326089us-gaap:NaturalGasProductionMember2020-01-012020-12-310001326089srt:NaturalGasLiquidsReservesMember2020-01-012020-12-310001326089us-gaap:OilAndCondensateMember2019-01-012019-12-310001326089us-gaap:NaturalGasProductionMember2019-01-012019-12-310001326089srt:NaturalGasLiquidsReservesMember2019-01-012019-12-310001326089srt:MinimumMember2020-01-012020-12-310001326089srt:MaximumMember2020-01-012020-12-310001326089us-gaap:AccumulatedOtherComprehensiveIncomeMember2020-01-012020-12-310001326089us-gaap:AccumulatedOtherComprehensiveIncomeMember2019-01-012019-12-310001326089us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMemberus-gaap:CustomerConcentrationRiskMember2020-12-310001326089snde:PioneerNaturalResourcesUsaInc.RelianceIndustriesAndNewpekLlcMember2020-12-310001326089snde:HydrocarbonGatheringAndHandlingAgreementMember2020-12-310001326089snde:CrudeOilAndCondensatePurchaseAgreementsMember2020-12-310001326089snde:PioneerNaturalResourcesUsaInc.RelianceIndustriesAndNewpekLlcMember2019-12-310001326089us-gaap:DrillingRightsMember2020-01-012020-12-310001326089us-gaap:DrillingRightsMember2019-01-012019-12-310001326089us-gaap:RetainedEarningsMember2020-01-012020-12-310001326089us-gaap:RetainedEarningsMember2019-01-012019-12-310001326089snde:DebtorInPossessionCreditFacilityMemberus-gaap:SubsequentEventMembersnde:RestructuringSupportAgreementMember2021-03-090001326089us-gaap:RevolvingCreditFacilityMember2021-01-010001326089us-gaap:RevolvingCreditFacilityMember2020-06-300001326089snde:TermLoanMember2018-04-2300013260892018-04-230001326089srt:MinimumMember2020-12-310001326089srt:MaximumMember2020-12-310001326089snde:TermLoanMemberus-gaap:SubsequentEventMember2021-01-310001326089snde:ProvedOilAndGasEffAssetsHeldInDimmitTexasMember2019-01-012019-12-310001326089us-gaap:FairValueInputsLevel2Member2020-12-310001326089snde:Year2023Membersnde:HoustonShipChannelNaturalGasMemberus-gaap:SwapMember2020-12-310001326089snde:Year2022Membersnde:HoustonShipChannelNaturalGasMemberus-gaap:SwapMember2020-12-310001326089snde:Year2022Membersnde:HenryHubNaturalGasMemberus-gaap:SwapMember2020-12-310001326089snde:Year2021Membersnde:WestTexasIntermediateCrudeOilMemberus-gaap:SwapMember2020-12-310001326089snde:Year2021Membersnde:HoustonShipChannelNaturalGasMemberus-gaap:SwapMember2020-12-310001326089snde:Year2021Membersnde:HenryHubNaturalGasMemberus-gaap:SwapMember2020-12-310001326089snde:Year2023Membersnde:WestTexasIntermediateCrudeOilMembersnde:CollarsMember2020-01-012020-12-310001326089snde:Year2022Membersnde:WestTexasIntermediateCrudeOilMembersnde:CollarsMember2020-01-012020-12-310001326089snde:Year2021Membersnde:WestTexasIntermediateCrudeOilMemberus-gaap:SwapMember2020-01-012020-12-310001326089snde:Year2021Membersnde:WestTexasIntermediateCrudeOilMembersnde:CollarsMember2020-01-012020-12-310001326089snde:Year2023Membersnde:HoustonShipChannelNaturalGasMemberus-gaap:SwapMember2020-01-012020-12-310001326089snde:Year2022Membersnde:HoustonShipChannelNaturalGasMemberus-gaap:SwapMember2020-01-012020-12-310001326089snde:Year2022Membersnde:HenryHubNaturalGasMemberus-gaap:SwapMember2020-01-012020-12-310001326089snde:Year2021Membersnde:HoustonShipChannelNaturalGasMemberus-gaap:SwapMember2020-01-012020-12-310001326089snde:Year2021Membersnde:HenryHubNaturalGasMemberus-gaap:SwapMember2020-01-012020-12-310001326089us-gaap:FairValueInputsLevel2Memberus-gaap:InterestRateSwapMember2019-12-310001326089us-gaap:InterestRateSwapMember2019-12-310001326089us-gaap:FairValueInputsLevel2Member2019-12-310001326089us-gaap:InterestRateSwapMemberus-gaap:NondesignatedMemberus-gaap:InterestExpenseMember2020-01-012020-12-310001326089us-gaap:CommodityContractMemberus-gaap:NondesignatedMemberus-gaap:GainLossOnDerivativeInstrumentsMember2020-01-012020-12-310001326089us-gaap:NondesignatedMember2020-01-012020-12-310001326089us-gaap:InterestRateSwapMemberus-gaap:NondesignatedMemberus-gaap:InterestExpenseMember2019-01-012019-12-310001326089us-gaap:CommodityContractMemberus-gaap:NondesignatedMemberus-gaap:GainLossOnDerivativeInstrumentsMember2019-01-012019-12-310001326089us-gaap:NondesignatedMember2019-01-012019-12-310001326089snde:DerivativeLiabilitiesCurrentMemberus-gaap:CommodityContractMemberus-gaap:NondesignatedMember2020-12-310001326089snde:DerivativeLiabilitiesNoncurrentMemberus-gaap:NondesignatedMember2020-12-310001326089snde:DerivativeLiabilitiesNoncurrentMemberus-gaap:InterestRateSwapMemberus-gaap:NondesignatedMember2019-12-310001326089snde:DerivativeLiabilitiesNoncurrentMemberus-gaap:CommodityContractMemberus-gaap:NondesignatedMember2019-12-310001326089snde:DerivativeLiabilitiesCurrentMemberus-gaap:InterestRateSwapMemberus-gaap:NondesignatedMember2019-12-310001326089snde:DerivativeLiabilitiesCurrentMemberus-gaap:CommodityContractMemberus-gaap:NondesignatedMember2019-12-310001326089snde:DerivativeLiabilitiesNoncurrentMemberus-gaap:NondesignatedMember2019-12-310001326089snde:DerivativeLiabilitiesCurrentMemberus-gaap:NondesignatedMember2019-12-310001326089snde:Year2023Membersnde:WestTexasIntermediateCrudeOilMembersnde:CollarsMember2020-12-310001326089snde:Year2022Membersnde:WestTexasIntermediateCrudeOilMembersnde:CollarsMember2020-12-310001326089snde:Year2021Membersnde:WestTexasIntermediateCrudeOilMembersnde:CollarsMember2020-12-310001326089us-gaap:FairValueInputsLevel2Memberus-gaap:CommodityContractMember2020-12-310001326089us-gaap:CommodityContractMember2020-12-310001326089us-gaap:FairValueInputsLevel2Memberus-gaap:CommodityContractMember2019-12-310001326089us-gaap:CommodityContractMember2019-12-310001326089snde:DerivativeAssetsCurrentMemberus-gaap:CommodityContractMemberus-gaap:NondesignatedMember2020-12-310001326089snde:DerivativeAssetsNoncurrentMemberus-gaap:InterestRateSwapMemberus-gaap:NondesignatedMember2019-12-310001326089snde:DerivativeAssetsNoncurrentMemberus-gaap:CommodityContractMemberus-gaap:NondesignatedMember2019-12-310001326089snde:DerivativeAssetsCurrentMemberus-gaap:InterestRateSwapMemberus-gaap:NondesignatedMember2019-12-310001326089snde:DerivativeAssetsCurrentMemberus-gaap:CommodityContractMemberus-gaap:NondesignatedMember2019-12-310001326089us-gaap:OilAndGasPropertiesMember2020-01-012020-12-310001326089us-gaap:OilAndGasPropertiesMember2019-01-012019-12-310001326089snde:DebtorInPossessionCreditFacilityMemberus-gaap:SubsequentEventMembersnde:FloorRateMember2021-03-310001326089snde:TermLoanMembersnde:FloorRateMember2020-12-310001326089srt:MinimumMemberus-gaap:RevolvingCreditFacilityMember2020-06-300001326089srt:MaximumMemberus-gaap:RevolvingCreditFacilityMember2020-06-300001326089snde:PaycheckProtectionProgramMember2020-05-120001326089snde:ExitSecondOutTermLoanFacilityMemberus-gaap:SubsequentEventMembersnde:RestructuringSupportAgreementMember2021-03-090001326089us-gaap:RevolvingCreditFacilityMember2020-12-310001326089snde:TermLoanMember2020-12-310001326089us-gaap:RevolvingCreditFacilityMember2019-12-310001326089snde:TermLoanMember2019-12-310001326089snde:DebtorInPossessionCreditFacilityMemberus-gaap:SubsequentEventMemberus-gaap:LondonInterbankOfferedRateLIBORMember2021-03-012021-03-310001326089srt:MinimumMemberus-gaap:SubsequentEventMemberus-gaap:PrimeMember2021-01-012021-03-310001326089srt:MaximumMemberus-gaap:SubsequentEventMemberus-gaap:PrimeMember2021-01-012021-03-310001326089srt:MinimumMembersnde:TermLoanMember2020-06-302020-06-300001326089srt:MaximumMembersnde:TermLoanMember2020-06-302020-06-300001326089snde:TermLoanMemberus-gaap:LondonInterbankOfferedRateLIBORMember2020-01-012020-12-310001326089srt:MinimumMemberus-gaap:RevolvingCreditFacilityMemberus-gaap:LondonInterbankOfferedRateLIBORMember2020-01-012020-12-170001326089srt:MaximumMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-170001326089srt:MaximumMemberus-gaap:RevolvingCreditFacilityMemberus-gaap:LondonInterbankOfferedRateLIBORMember2019-01-012019-12-310001326089us-gaap:CommonStockMember2019-11-262019-11-260001326089snde:PurchaserThreeMemberus-gaap:SalesRevenueProductLineMemberus-gaap:CustomerConcentrationRiskMember2020-01-012020-12-310001326089snde:PurchaserOneMemberus-gaap:SalesRevenueProductLineMemberus-gaap:CustomerConcentrationRiskMember2020-01-012020-12-310001326089us-gaap:OilAndGasMemberus-gaap:AccountsReceivableMemberus-gaap:CustomerConcentrationRiskMember2019-01-012019-12-310001326089snde:PurchaserTwoMemberus-gaap:SalesRevenueProductLineMemberus-gaap:CustomerConcentrationRiskMember2019-01-012019-12-310001326089snde:PurchaserOneMemberus-gaap:SalesRevenueProductLineMemberus-gaap:CustomerConcentrationRiskMember2019-01-012019-12-3100013260892019-11-0100013260892019-10-3100013260892019-11-260001326089snde:EquityIncentivePlan2020Member2020-07-310001326089snde:ServiceBasedAwardsMember2020-01-012020-12-310001326089snde:ServiceBasedAwardsMember2019-01-012019-12-310001326089us-gaap:AdditionalPaidInCapitalMember2020-01-012020-12-310001326089us-gaap:AdditionalPaidInCapitalMember2019-01-012019-12-310001326089us-gaap:OilAndGasMemberus-gaap:AccountsReceivableMemberus-gaap:CustomerConcentrationRiskMember2020-12-310001326089us-gaap:OilAndGasMemberus-gaap:AccountsReceivableMemberus-gaap:CustomerConcentrationRiskMember2019-12-310001326089snde:EagleFordFormationMember2020-12-310001326089snde:EagleFordFormationMember2019-12-310001326089srt:OilReservesMember2020-12-310001326089srt:NaturalGasReservesMember2020-12-310001326089srt:NaturalGasLiquidsReservesMember2020-12-310001326089srt:OilReservesMember2019-12-310001326089srt:NaturalGasReservesMember2019-12-310001326089srt:NaturalGasLiquidsReservesMember2019-12-310001326089srt:OilReservesMember2018-12-310001326089srt:NaturalGasReservesMember2018-12-310001326089srt:NaturalGasLiquidsReservesMember2018-12-3100013260892018-12-310001326089srt:OilReservesMember2020-01-012020-12-310001326089srt:NaturalGasReservesMember2020-01-012020-12-310001326089srt:NaturalGasLiquidsReservesMember2020-01-012020-12-310001326089srt:OilReservesMember2019-01-012019-12-310001326089srt:NaturalGasReservesMember2019-01-012019-12-310001326089srt:NaturalGasLiquidsReservesMember2019-01-012019-12-310001326089snde:TermLoanMemberus-gaap:SubsequentEventMembersnde:RestructuringSupportAgreementMember2021-03-090001326089us-gaap:RestrictedStockUnitsRSUMember2020-12-310001326089us-gaap:RestrictedStockUnitsRSUMember2019-12-310001326089snde:EagleFordFormationMember2019-01-012019-12-310001326089snde:CoronavirusAidReliefAndEconomicSecurityActMember2020-10-012020-12-310001326089us-gaap:RevolvingCreditFacilityMember2020-06-302020-06-300001326089snde:TermLoanMember2020-06-302020-06-300001326089snde:TermLoanMember2020-01-012020-12-310001326089srt:MinimumMembersnde:ProjectedPeriodThirtySixMonthsMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-310001326089srt:MaximumMembersnde:ProjectedPeriodThirtySixMonthsMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-310001326089us-gaap:InterestRateSwapMember2020-12-012020-12-310001326089snde:AmericanDepositorySharesMember2019-11-262019-11-260001326089snde:EagleFordFormationMember2020-01-012020-12-310001326089us-gaap:OilAndGasMemberus-gaap:AccountsReceivableMemberus-gaap:CustomerConcentrationRiskMember2020-01-012020-12-310001326089snde:CoronavirusAidReliefAndEconomicSecurityActMembersnde:TaxYearsBeginningJanuary12019And2020Membersnde:CoronavirusDisease2019PandemicMember2020-03-272020-03-270001326089snde:PriorToCoronavirusAidReliefAndEconomicSecurityActMembersnde:TaxYearsBeginningJanuary12019And2020Member2019-01-012020-03-260001326089snde:TermLoanMemberus-gaap:SubsequentEventMember2021-01-012021-01-310001326089us-gaap:RevolvingCreditFacilityMember2020-12-182021-03-090001326089us-gaap:LetterOfCreditMemberus-gaap:SubsequentEventMembersnde:RestructuringSupportAgreementMember2021-03-090001326089snde:ReserveBasedLendingRevolvingCreditFacilityMemberus-gaap:SubsequentEventMembersnde:RestructuringSupportAgreementMember2021-03-090001326089srt:MaximumMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-310001326089snde:PaycheckProtectionProgramMember2020-01-012020-12-310001326089srt:MinimumMembersnde:ProjectedPeriodThirtySevenToSixtyMonthsMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-310001326089srt:MaximumMembersnde:ProjectedPeriodThirtySevenToSixtyMonthsMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-310001326089snde:ProjectedPeriodThirtySixMonthsMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-310001326089snde:ProjectedPeriodThirtySevenToSixtyMonthsMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-310001326089us-gaap:OtherIncomeMember2020-01-012020-12-310001326089snde:TermLoanMemberus-gaap:SubsequentEventMembersnde:RestructuringSupportAgreementMember2021-03-092021-03-090001326089us-gaap:RevolvingCreditFacilityMember2020-01-310001326089snde:DiscontinuedOperationDimmitCountyTexasMember2019-10-010001326089us-gaap:DiscontinuedOperationsDisposedOfBySaleMember2019-10-012019-10-010001326089us-gaap:SwapMemberus-gaap:SubsequentEventMember2021-01-012021-01-310001326089us-gaap:SwapMemberus-gaap:SubsequentEventMember2021-01-012021-03-310001326089us-gaap:NondesignatedMember2020-12-310001326089us-gaap:NondesignatedMember2019-12-310001326089snde:PioneerNaturalResourcesUsaInc.RelianceIndustriesAndNewpekLlcMember2020-01-012020-12-310001326089snde:PioneerNaturalResourcesUsaInc.RelianceIndustriesAndNewpekLlcMember2019-01-012019-12-310001326089snde:DebtorInPossessionCreditFacilityMemberus-gaap:SubsequentEventMember2021-03-3100013260892020-06-302020-06-3000013260892020-10-012020-12-3100013260892020-04-012020-09-3000013260892020-05-012020-12-3100013260892020-05-012020-09-300001326089srt:MinimumMemberus-gaap:RevolvingCreditFacilityMember2020-01-012020-12-3100013260892019-12-3100013260892019-01-012019-12-310001326089srt:MinimumMembersnde:TermLoanMember2020-01-012020-12-3100013260892020-12-3100013260892020-06-1200013260892020-06-3000013260892021-03-3100013260892020-01-012020-12-31snde:customersnde:locationiso4217:USDutr:bbliso4217:USDutr:Mcfutr:MBblsutr:MMcfiso4217:USDxbrli:sharesiso4217:USDutr:MMBTUsnde:segmentxbrli:sharesiso4217:USDxbrli:pureutr:MMBTUutr:bblutr:acresnde:itemutr:MBoesnde:installment

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2019
	OR
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


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

	For the fiscal year ended December 31, 2020

	OR

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

For the transition period from ___________ to _________

~~Commission File Number 001‑36302~~

Commission File Number 001-36302

Sundance Energy Inc.

(Exact name of Registrant as specified in its Charter)

Delaware	61‑1949225
(State or other jurisdiction ofincorporation or organization)	(I.R.S. EmployerIdentification No.)
1050 17th Street, Suite 700, Denver, CO	80265
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (303) 543‑5700


Delaware	61-1949225
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1050 17^th Street, Suite 700, Denver, CO	80265
(Address of principal executive offices)	(Zip Code)

~~Securities Registered Pursuant to Section 12(b) of the Act:~~

Title of each class		Trading Symbol(s)		Name of Exchange on Which Registered
Common Stock, par value $0.001 per share		SNDE		The Nasdaq Stock Market LLC

Registrant’s telephone number, including area code: (303) 543-5700

~~Securities registered pursuant to Section 12(g) of the Act: None~~

Securities Registered Pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: Common Stock, par value $0.001

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 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 definition 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 ☑~~


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 Exchange Act). YES ☐ NO ☑

The aggregate market value of the registrant’s common stock held by non-affiliates, based on the closing price of the registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter, was $131,992,965. The number of outstanding shares of the registrant’s common stock as of April 24, 2020 was 6,875,672.

~~DOCUMENTS~~The ~~INCORPORATED~~aggregate BYmarket ~~REFERENCE~~ value of the registrant’s common stock held by non-affiliates, based on the closing price of the registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter, was $19,711,397. The number of outstanding shares of the registrant’s common stock as of March 31, 2021 was 6,876,422.

Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s Definitive Proxy Statement on Schedule 14A relating to its 2020 annual meeting of stockholders to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended.

Table of Contents

PART I
Item 1.	Business	4
Item 1A.	Risk Factors	1921
Item 1B.	Unresolved Staff Comments	4146
Item 2.	Properties	4146
Item 3.	Legal Proceedings	4146
Item 4.	Mine Safety Disclosures	4147
PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	41
PART II
Item 6.	Selected Financial Data	42
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	47
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 6.	Selected Financial Data	47
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	47
Item 8.	Financial Statements and Supplementary Data	55
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	55
Item 8.	Financial Statements and Supplementary Data	59
Item 9A.	Controls and Procedures	56
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	59
Item 9B.	Other Information	57
Item 9A.	Controls and Procedures	60
PART III
Item 9B.	Other Information	60
Item 10.	Directors, Executive Officers and Corporate Governance	57

Item 11.	Executive Compensation	57
PART III
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	57
Item 10.	Directors, Executive Officers and Corporate Governance	61
Item 13.	Certain Relationships and Related Transactions, and Director Independence	58
Item 11.	Executive Compensation	69
Item 14.	Principal Accounting Fees and Services	58
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	75
PART IV
Item 13.	Certain Relationships and Related Transactions, and Director Independence	76
Item 15.	Exhibits Financial Statement Schedules	58
Item 14.	Principal Accounting Fees and Services	77
Item 16	Form 10‑K Summary	58

EXHIBIT INDEX		101
PART IV
SIGNATURES		105
Item 15.	Exhibits Financial Statement Schedules	77
Item 16	Form 10-K Summary	77

EXHIBIT INDEX		118

SIGNATURES		122

Table of Contents

Glossary of Selected Oil and Natural Gas Terms

All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this annual report on Form 10-K (this “annual report”). As used in this document:

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of oil or other liquid hydrocarbons.

Boe. Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Boe/d. Barrels of oil equivalent per day.

Completion. A process of treating a drilled well, including hydraulic fracturing among other stimulation processes, followed by the installation of permanent equipment for the production of oil or natural gas.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Held-by-production acreage. Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or gas.

Hydraulic fracturing or fracking. The technique of pumping a mixture of fluids into a well to rupture the rock, creating artificial channels. As part of this technique, sand or other material may also be injected into the formation to keep the channels open, so that fluids or natural gases may more easily flow through the formation.

MBoe. Thousand barrels of oil equivalent with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

MMBoe. Million barrels of oil equivalent with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Mcf. Thousand cubic feet of natural gas.

MMBtu. Million British Thermal Units.

Natural gas liquids or NGLs. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be. An owner who has 50% interest in 100 acres owns 50 net acres.

NYMEX. New York Mercantile Exchange.

Proved reserves. Those reserves 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 regulation 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 estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

Table of Contents

Proved undeveloped reserves or PUD. 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 for recompletion. Reserves on undrilled acreage shall be 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. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas regardless of whether or not such acreage contains proved reserves.

Working interest. A cost-bearing interest under an oil and gas lease that gives the holder the right to develop and produce the minerals under the lease.

Workover. The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

WTI. means the West Texas Intermediate spot price.

Cautionary Statement Regarding Forward-Looking Statements

Certain statements contained in this annual report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements are identified by the use of the words “project,” “believe,” “estimate,” “expect,” “anticipate,” “intend,” “contemplate,” “foresee,” “would,” “could,” “plan,” and similar expressions that are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that are anticipated. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

~~· our assumptions about energy markets;~~

·● our ability to ~~execute~~consummate ~~our~~the ~~business~~transactions ~~strategies~~associated with the Company’s current bankruptcy court proceeding;

·● ~~the~~our ~~volatility~~ability to obtain in a timely manner confirmation of ~~realized~~a ~~oil,~~successful ~~natural~~plan ~~gas~~of ~~and~~reorganization ~~NGL~~in ~~prices~~the Company’s current bankruptcy court proceeding;

·● ~~general~~the ~~economic~~outbreak and effect of communicable diseases, ~~business~~such ~~and~~as ~~industry~~coronavirus ~~conditions~~(“COVID-19”);

·● ~~the~~our ~~overall~~assumptions ~~supply~~about ~~and~~energy ~~demand for oil and natural gas, and regional supply and demand factors, delays, or interruptions of production~~markets;

·● our ability to ~~replace~~execute our ~~oil,~~business ~~natural gas and NGL reserves~~strategies;

·● ~~our~~the ~~ability~~volatility toof ~~identify~~realized oil, ~~complete~~natural gas and ~~integrate~~NGL ~~acquisitions~~prices;

·● ~~competition~~general ineconomic, ~~the~~business ~~oil~~ and ~~natural gas~~ industry conditions;

·● the ~~ability~~overall tosupply ~~obtain~~and ~~capital~~demand orfor ~~financing~~oil ~~needed~~and ~~for~~natural ~~development~~gas, and ~~exploration~~regional ~~operations~~supply onand ~~favorable~~demand ~~terms~~factors, delays, or atinterruptions ~~all~~of production;

●

our ability to replace our oil, natural gas and NGL reserves;

Table of Contents

·● ~~title~~our ~~defects~~ability into ~~our~~identify, ~~properties~~complete and integrate acquisitions;

·● ~~uncertainties~~competition ~~inherent~~ in ~~estimating~~the oil, ~~gas~~ and ~~NGL~~natural ~~reserves~~gas industry;

·● the ~~extent~~ability to ~~which~~obtain wecapital ~~are~~or ~~successful~~financing inneeded ~~acquiring~~for development and ~~discovering~~exploration ~~additional~~operations ~~reserves~~on favorable terms, or at all;

·● ~~our~~title ~~ability~~defects toin ~~obtain~~our ~~permits and licenses~~properties;

·● ~~the~~uncertainties ~~availability~~inherent orin ~~cost~~estimating ~~of rigs~~oil, ~~equipment,~~gas ~~raw~~and ~~materials,~~NGL ~~supplies, oilfield services or personnel~~reserves;

·● the ~~potential~~extent ~~impact of government regulations, including current and proposed legislation and regulations related~~ to ~~hydraulic~~which ~~fracturing,~~we ~~oil~~are ~~and~~successful ~~natural~~in ~~gas~~acquiring ~~drilling, air emissions~~ and ~~climate~~discovering ~~change,~~additional ~~conservation measures, regulatory determinations, litigation and competition~~reserves;

·● ~~the~~our ~~availability~~ability ofto ~~pipeline~~obtain ~~capacity~~permits and ~~transportation facilities~~licenses;

·● ~~operating~~the ~~hazards~~availability ~~and~~or ~~other~~cost ~~risks~~of ~~associated~~rigs, ~~with~~equipment, ~~oil~~raw ~~and~~materials, ~~gas~~supplies, ~~operations~~oilfield services or personnel;

·● the ~~cost~~potential impact of ~~inflation~~government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, oil and natural gas drilling, air emissions and climate change, conservation measures, regulatory determinations, litigation and competition;

·● ~~impairments~~the availability of ~~proved~~pipeline orcapacity ~~unproved~~and ~~properties~~transportation ~~or other long-lived assets~~facilities;

·● ~~the~~operating ~~impact~~hazards ofand ~~derivative~~other ~~instruments~~risks associated with oil and gas operations;

·● ~~our ability to realize~~ the ~~benefits~~cost of ~~our redomiciliation from Australia to the United States~~inflation;

·● ~~our~~impairments ~~dependence~~of onproved ~~our~~or ~~key~~unproved ~~personnel~~properties or other long-lived assets;

·● the ~~outbreak~~impact of ~~communicable~~derivative ~~diseases, such as coronavirus (“COVID-19”)~~instruments;

·● our ability to realize the ~~effectiveness~~benefits of our ~~internal~~redomiciliation ~~control~~from ~~over~~Australia ~~financial~~to ~~reporting~~the United States;

·● our ~~ability~~dependence toon ~~continue~~our askey ~~a going concern~~personnel;

·● ~~physical,~~the ~~digital,~~effectiveness of our internal, ~~and~~control ~~external~~over ~~security~~financial ~~breaches~~reporting;

·● ~~technological~~our ~~advances;~~ability ~~and~~to continue as a going concern;

·● ~~other~~physical, ~~factors~~digital, ~~discussed~~internal, ~~below~~ and ~~elsewhere~~external insecurity ~~this annual report.~~breaches;

~~Known~~● ~~material~~technological ~~factors~~advances; that could cause actual results to differ materially from those in our expectations as it relates to our recent redomiciliation to the U.S. include, amongst other factors, changes in U.S. or non-U.S. laws that could reduce or eliminate the benefits expected to be achieved from our redomiciliation, an inability to realize expected benefits from the redomiciliation or the occurrence of difficulties that arise as a result, or in connection with, the redomiciliation. For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read Part I, Item 1A. “Risk Factors” of this annual report. and

●

other factors discussed below and elsewhere in this annual report.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read Part I, Item 1A. “Risk Factors” of this annual report.

Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those described in this annual report as anticipated, believed, estimated or expected. Accordingly, you should not place undue reliance on these forward-looking statements. These statements speak only as of the date of this annual report and will not be revised or updated to reflect events after the date of this annual report.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Table of Contents

Presentation of Information

On November 26, 2019, Sundance Energy Inc., a newly formed Delaware corporation, acquired all of the issued and outstanding ordinary shares of Sundance Energy Australia Limited, a public company incorporated under the laws of the State of South Australia (“SEAL”), and former parent company of the Sundance group of companies, pursuant to a Scheme of Arrangement under Australian law, which was approved by the Federal Court of Australia on November 14, 2019, and by SEAL shareholders at a meeting of shareholders, which approval was obtained on November 8, 2019 (the “Redomiciliation”). All of the issued and outstanding shares of SEAL were exchanged for newly issued shares of common stock of Sundance Energy Inc., on the basis of one share of common stock for every 100 ordinary shares of SEAL issued and outstanding. Holders of SEAL’s American Depository Shares (“ADSs”) (each of which represented 10 ordinary shares) received one share of common stock for every 10 ADSs held. Thereafter, SEAL distributed all of its assets to Sundance Energy Inc., and Sundance Energy Inc. assumed all of the liabilities of SEAL. SEAL was dissolved on January 24, 2021.

The purpose of the Redomiciliation was to reorganize the operations of SEAL into a structure whereby the ultimate parent company of the Sundance group of companies would be a Delaware corporation. In connection with the Redomiciliation, the ordinary shares of SEAL were delisted from the Australian Securities Exchange, and the common stock of Sundance Energy Inc. began trading on the Nasdaq Global Market on November 26, 2019 under the ticker symbol “SNDE”, the same symbol under which SEAL’s ADSs were traded on Nasdaq Global Market prior to the implementation of the Redomiciliation.

~~Sundance~~The ~~Energy,~~purpose ~~Inc.,~~of athe ~~Colorado~~Redomiciliation ~~corporation~~was ~~(“SEI”),~~to areorganize ~~subsidiary~~the operations of SEAL ~~prior~~into toa ~~the~~structure ~~Redomiciliation,~~whereby ~~has historically been~~ the ~~U.S.~~ultimate ~~operating~~parent company ~~for~~of the Sundance group of companies would be a Delaware corporation. ~~Following~~In connection with the Redomiciliation, ~~SEI~~the ~~will~~ordinary ~~continue~~shares inof ~~the~~SEAL ~~role~~were ofdelisted ~~U.S.~~from ~~operating~~the ~~company~~Australian asSecurities aExchange, ~~subsidiary~~and the common stock of Sundance Energy Inc. began trading on the Nasdaq Global Market on November 26, 2019 under the ticker symbol “SNDE”, the same symbol under which SEAL’s ADSs were traded on Nasdaq Global Market prior to the implementation of the Redomiciliation. The Company was delisted from the Nasdaq Global Market on March 19, 2021 and began trading on the Pink Open Market under the symbol “SNDEQ.”

Sundance Energy, Inc., a Colorado corporation (“SEI”), a subsidiary of SEAL prior to the Redomiciliation, has historically been the U.S. operating company for the Sundance group of companies. Following the Redomiciliation, SEI continued in the role of U.S. operating company as a subsidiary of Sundance Energy Inc.

Unless the context otherwise requires, references to “Sundance,” “we,” “us,” “our,” and the “Company” refer to (i) SEAL and its subsidiaries prior to the Redomiciliation and (ii) Sundance Energy Inc. and its subsidiaries upon completion of the Redomiciliation, as applicable.

PART I

Item 1. Business.

General

We are an onshore independent oil and natural gas company focused on the development, production and exploration of large, repeatable resource plays in North America. Our operations consist primarily of drilling and production from unconventional horizontal wells targeting the Eagle Ford formation in South Texas.

~~Strategy~~

~~Our~~Bankruptcy ~~strategy~~Proceedings isunder toChapter acquire and/or develop assets where we are operator and have high working interests, positioning us to efficiently control the pace and scope of our development and the allocation of our capital resources. We also believe that serving as operator allows us to control the drilling, completion, operations and marketing of sold volumes. We plan to continue to focus on developing high-return assets from our portfolio, while preserving an attractive oil-rich inventory. We continue to realize cost improvement by reducing our operating costs and per well drilling and completion costs. We intend to manage our liquidity by scaling our 2020 capital program to remain within our operating cash flow. We believe execution of each of these focus areas should increase long-term shareholder value. 11

Restructuring Support Agreement

On March 9, 2021, we entered into a Restructuring Support Agreement (the “RSA”) with (i) Toronto Dominion (Texas) LLC, as agent pursuant to the Revolving Facility (as defined below), (ii) the lenders party to that certain Credit Agreement, dated as of July 18, 2018 (as amended, modified, or supplemented), (the “Senior Lenders” and such facility, the “Revolving Facility”), (iii) Morgan Stanley Capital Administrators Inc. as agent pursuant to the Term Loan Facility (as defined below), and (iv) the lenders party to that certain Amended & Restated Term Loan Credit Agreement, dated as of April 23, 2018 (as amended, modified, or supplemented from time to time), (the “Term Lenders” and such facility, the “Term Loan Facility”).

Table of Contents

The RSA contemplates, among other things:

•

Funding of the Cases. The Chapter 11 Cases (as defined below) will be financed by a new up to $50 million junior priority debtor-in-possession credit facility (the “DIP Facility”) provided by certain of the Term Lenders (the “DIP Lenders”).

•

Exit Facilities. On the effective date of the Prepackaged Plan (as defined below), we will enter into the following:

◾

Exit RBL Facility. Sundance and its subsidiaries and each Senior Lender that elects to participate in will enter into a new reserve-based lending revolving credit facility having a borrowing base of $107.5 million (inclusive of a $20.0 million letter of credit subfacility) (the “Exit RBL Facility”).

◾

Exit Second Out Term Loan Facility. Sundance and its subsidiaries and each Senior Lender that elects to participate in the Exit RBL Facility will enter into the Exit Second Out Term Loan Facility, which will be a new first lien second out term loan facility having a principal amount of $30.0 million.

•

Prepetition Revolving Facility Claims.

◾

Each holder of a Prepetition Revolving Facility claim that votes to accept the Prepackaged Plan will receive: (i) its pro rata share of the loans under the Exit RBL Facility; (ii) its pro rata share of the loans under the Exit Second Out Term Loan Facility; and (iii) its pro rata share of the cash paydown.

•

Prepetition Term Loan Claims. Each holder of a Prepetition Term Loan claim will receive its pro rata share of 100% of the new common equity interests of Sundance (subject to dilution by a 6% management incentive plan).

•

General Unsecured Claims. The legal, equitable, and contractual rights of holders of general unsecured claims will be unaltered by the Prepackaged Plan. On or as soon as practicable after the earliest to occur of the Effective Date of the Prepackaged Plan and the date a general unsecured claim becomes due in the ordinary course of business, each holder of a general unsecured claim will receive payment in full in cash on account of its general unsecured claim or such other treatment as would render such claim unimpaired.

•

All existing common stock in Sundance (the “Old Parent Interests”) will be cancelled, and each holder of an Old Parent Interest will not receive any distribution or retain any property on account of such Old Parent Interest.

Upon emergence from bankruptcy, we expect that we will no longer be a publicly traded company.

Table of Contents

Voluntary Chapter 11 Bankruptcy Proceedings

On March 9, 2021 (the “Petition Date”), the Company and all of its subsidiaries (collectively, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions,” and the cases commenced thereby, collectively, the “Chapter 11 Cases”) under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) to pursue the Joint Prepackaged Plan of Reorganization for Sundance Energy Inc. and Its Affiliate Debtors Under Chapter 11 of the Bankruptcy Code (as amended, restated, supplemented or otherwise modified from time to time, the “Prepackaged Plan”). The Debtors are authorized to operate their businesses as debtors in possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

The Bankruptcy Court has granted on a final basis all of the first day motions filed by the Debtors seeking relief that would minimize the impact of the Chapter 11 Cases on the Company’s operations, customers and employees. As a result, the Company is not only authorized to conduct business activities in the ordinary course and generally pay all associated obligations for the period following the Petition Date without further Bankruptcy Court approval, but it is also currently authorized to pay and has paid, subject to certain limitations, obligations that arose prior to the Petition Date related to taxes, insurance, surety bonds, employee wages and benefits, services and supplies provided by vendors in the ordinary course of business and mineral interests held by royalty holders and other partners. In general, during the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business require the prior approval of the Bankruptcy Court. As a result of the automatic stay under the Bankruptcy Code, which became effective upon the commencement of the Chapter 11 Cases, most judicial or administrative actions against the Company by its creditors to collect on or otherwise exercise rights or remedies with respect to claims that arose before the Petition Date are stayed during the pendency of the Chapter 11 Cases.

A hearing to consider confirmation of the Prepackaged Plan and final approval of the Debtors’ related disclosure statement is currently scheduled to begin on April 19, 2021.

For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with our Chapter 11 cases as described in Item 1A, “Risk Factors.” As a result of these risks and uncertainties, our assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Annual Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

For a further description of these matters, see Note 15 - Subsequent Events.

Strategy

Our strategy is to acquire and/or develop assets where we are the operator and have high working interests, positioning us to efficiently control the pace and scope of our development and the allocation of our capital resources. We also believe that serving as operator allows us to control the drilling, completion, operations and marketing of sold volumes. Upon emergence from bankruptcy, we plan to continue to focus on developing high-return assets from our portfolio, while preserving an attractive oil-rich inventory. Throughout 2020, we continued to realize cost improvement by reducing our operating costs and per well drilling and completion costs. Upon emergence from bankruptcy, we intend to manage our liquidity by scaling our 2021 capital program to remain within our operating cash flow.

Table of Contents

Oil and Natural Gas Properties

Description of Properties

All of our operations and assets are located in the Eagle Ford formation in South Texas. Since entering the Eagle Ford play in 2014, we have built a strong assets base that includes over 4138,000 net acres targeting the Eagle Ford, through a combination of property acquisitions and development of proved reserves. Our 2018 acquisition of approximately 21,900 net acres in the Eagle Ford in McMullen, Live Oak, Atascosa and La Salle counties, Texas has positioned us to compete more effectively in this market by offering economies of scale and positioning us to compete for further acquisition opportunities in this area. As of December 31, ~~2019~~2020, we operated 9795% of our net producing wells and our average working interest in our operated wells was approximately 9596%.

Estimated Proved Reserves

The following table presents summary information regarding our estimated net proved oil, natural gas and NGL reserves as of the dates indicated. The estimates of our net proved reserves as of December 31, 2019 and 2018 are based on the reserve reports prepared by Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineers, in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting. For more information about our proved reserves as of December 31, 2019 and 2018, please see the reports to management prepared by Ryder Scott, which have been filed or incorporated by reference, as exhibits to this annual report. All of reserves were located in the Eagle Ford.

	As of December 31,
	2019		2018
Estimated proved reserves:
Oil (MBbls)		62,788		58,629
Natural gas (MMcf)		120,904		108,841
NGL (MBbls)		18,134		16,472
Total estimated proved reserves (MBoe)		101,072		93,241
Estimated proved developed reserves:
Oil (MBbls)		16,101		16,742
Natural gas (MMcf)		26,930		33,169
NGL (MBbls)		4,022		4,927
Total estimated proved developed reserves (MBoe)		24,611		27,197
Estimated proved undeveloped reserves:
Oil (MBbls)		46,687		41,887
Natural gas (MMcf)		93,974		75,672
NGL (MBbls)		14,112		11,545
Total estimated proved undeveloped reserves (MBoe)		76,461		66,044
PV‑10 (in thousands)	$	752,593	$	1,109,847
Standardized Measure (in thousands)	$	675,099	$	952,625

The following table presents summary information regarding our estimated net proved oil, natural gas and NGL reserves as of the dates indicated. The estimates of our net proved reserves as of December 31, 2020 and 2019 are based on the reserve reports prepared by Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineers, in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting. For more information about our proved reserves as of December 31, 2020 and 2019, please see the reports to management prepared by Ryder Scott, which have been filed or incorporated by reference, as exhibits to this annual report. All of the reserves were located in the Eagle Ford.


	As of December 31,
	2020		2019
Estimated proved reserves:
Oil (MBbls)		28,898		62,788
Natural gas (MMcf)		50,145		120,904
NGL (MBbls)		8,171		18,134
Total estimated proved reserves (MBoe)		45,427		101,072
Estimated proved developed reserves:
Oil (MBbls)		12,156		16,101
Natural gas (MMcf)		22,667		26,930
NGL (MBbls)		3,401		4,022
Total estimated proved developed reserves (MBoe)		19,335		24,611
Estimated proved undeveloped reserves:
Oil (MBbls)		16,742		46,687
Natural gas (MMcf)		27,478		93,974
NGL (MBbls)		4,770		14,112
Total estimated proved undeveloped reserves (MBoe)		26,092		76,461
PV‑10 (in thousands)	$	231,094	$	752,593
Standardized Measure (in thousands)	$	230,804	$	675,099

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil, natural gas and NGLs that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers may vary and are subject to change with additional data. Furthermore, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, operational changes, regulatory changes, environmental protection, prices and costs, and reservoir performance. Please read Part I, Item IA. “Risk Factors” of this annual report.

Table of Contents

Additional information regarding our proved reserves can be found in our Consolidated Financial Statements and Notes thereto included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report.

~~PV‑10~~

~~Certain of our oil and natural gas reserve disclosures included in this annual report are presented on a~~ PV‑10 basis. PV‑10 is the estimated present value of the future cash flows less future development and production costs from our proved reserves before income taxes discounted using a 10% discount rate. PV‑10 may be considered a non-GAAP financial measure as defined by the SEC because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows (the “Standardized Measure”). We believe that PV‑10 is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe that the use of a pre-tax measure provides greater comparability of assets when evaluating companies. Investors should be cautioned that neither PV‑10 nor Standardized Measure represents an estimate of the fair market value of our proved reserves.

Certain of our oil and natural gas reserve disclosures included in this annual report are presented on a PV-10 basis. PV-10 is the estimated present value of the future cash flows less future development and production costs from our proved reserves before income taxes discounted using a 10% discount rate. PV-10 may be considered a non-GAAP financial measure as defined by the SEC because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows (the “Standardized Measure”). We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe that the use of a pre-tax measure provides greater comparability of assets when evaluating companies. Investors should be cautioned that neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our proved reserves.

The following table provides a reconciliation of Standardized Measure to PV-10 (in thousands):

	As of December 31,
	2019		2018
Standardized Measure	$	675,099	$	952,625
Present value of future income tax discounted at 10%		77,494		157,222
PV‑10 of proved reserves	$	752,593	$	1,109,847


	As of December 31,
	2020		2019

Standardized Measure	$	230,804	$	675,099
Present value of future income tax discounted at 10% ⁽¹⁾		290		77,494
PV‑10 of proved reserves	$	231,094	$	752,593

(1)

As of December 31, 2020 the estimated taxable income to be generated from 2020 year-end reserves was expected to be almost fully offset by net operating loss carryforwards.

Proved Undeveloped Reserves

Annually, management develops a five-year development plan based on our best available data at the time the plan is developed. Our five-year plan incorporates a development plan for converting PUD reserves to proved developed. The development plan includes only PUD reserves that we are reasonably certain will be spud within five years of initial booking based upon management’s evaluation of a number of qualitative and quantitative factors, including estimated risk-based returns, commodity prices and cost forecasts and recent drilling and well performance. Our five-year development plan generally does not contemplate a uniform conversion of our PUD reserves to proved developed. At December 31, 2019, our short-term strategy was to slow the pace of development in 2020 and 2021, which would allow cash flow to accumulate. The accumulated cash flow would be used to fund an increased pace of development in later years, such that all remaining proved undeveloped locations would be developed within the five-year period.

Annually, management develops a five-year development plan based on our best available data at the time the plan is developed. Our five-year plan incorporates a development plan for converting PUD reserves to proved developed. The development plan includes only PUD reserves that we are reasonably certain will be spud within five years of initial booking based upon management’s evaluation of a number of qualitative and quantitative factors, including estimated risk-based returns, commodity prices and cost forecasts and recent drilling and well performance. Our five-year development plan generally does not contemplate a uniform conversion of our PUD reserves to proved developed. Since the beginning of the COVID-19 pandemic and at December 31, 2020, our strategy was to discontinue development, which would allow cash flow to accumulate to improve liquidity. Upon emergence from bankruptcy, we plan to use accumulated cash flow to fund an increased pace of development in later years, such that all remaining proved undeveloped locations would be developed within the five-year period.

Management reviews and revises the development plan throughout the year and may modify the development plan after evaluating the factors noted above, as well as realized commodity prices, cost and availability of services and equipment, acquisition and divestiture activity; and our current and projected financial condition and liquidity. If there are changes that result in certain PUD reserves no longer being scheduled for development within five years from the date of initial booking, we reclassify those PUD reserve locations to unproved reserve categories. In addition, PUD locations and reserves may be removed from the development plan prior to their five-year expiration as a result of changes in our development plan related to factors discussed above.

Table of Contents

The following table summarizes our changes in PUDs during the years ended December 31, ~~2019~~2020:

		PUD Reserves
		(MBoe)
As of December 31, 2018		66,044
Extensions and discoveries		36,535
Sales of reserves in place		(1,736)
Revisions of prior estimates		(19,881)
Conversion of proved undeveloped to proved developed		(4,501)
As of December 31, 2019		76,461

During the year ended December 31, 2019, we incurred capital expenditures of approximately $69.5 million to convert proved undeveloped reserves to proved developed reserves. The remainder of capital expenditures for our proved properties for the period were related to wells in process, development of reserve locations that were not previously classified as proved, infrastructure and installation of artificial lift on proved developed producing reserves.


		PUD Reserves
		(MBOE)
As of December 31, 2019		76,461
Extensions and discoveries		3,945
Sales of reserves in place		—
Revisions of prior estimates		(51,207)
Conversion of proved undeveloped to proved developed		(3,107)
As of December 31, 2020		26,092

As of December 31, 2019, our proved undeveloped reserves were approximately 76,461 MBoe, an increase of 10,417 MBoe over our December 31, 2018 proved undeveloped reserves estimate of approximately 66,044 MBoe. The change primarily resulted from proved undeveloped locations added in 2019 as result of our technical evaluation of wells drilled and completed in late 2018 and in 2019 on properties acquired in 2018 (total extensions of 36,535 MBoe). As of December 31, 2018, we were still in the process of evaluating many of the undeveloped locations acquired in 2018, and at that time approximately half of the undeveloped locations in our development plan were on acreage acquired in the 2018 Eagle Ford acquisition. The remainder of the December 31, 2018 proved undeveloped locations were on properties that we owned prior to the 2018 acquisition. As a result of our additional technical evaluation of the acquired properties during 2019, the focus of our development plan shifted to properties acquired in 2018 with higher projected returns, and we had revisions of 19,881 MBoe primarily associated with approximately 50 proved undeveloped locations on legacy properties that were removed because we expect them to be drilled outside the 5-year window.

During the year ended December 31, 2020, we incurred capital expenditures of approximately $35.5 million to convert proved undeveloped reserves to proved developed reserves. The remainder of capital expenditures for our proved properties for the period were primarily related to infrastructure and installation of artificial lift on proved developed producing reserves.

As of December 31, 2020, our proved undeveloped reserves were approximately 26,092 MBoe, a decrease of 50,369 MBoe over our December 31, 2019 proved undeveloped reserves estimate of approximately 76,461 MBoe. The change primarily resulted from approximately 118 proved undeveloped locations being removed as we expect them to be drilled outside the 5-year window as a result of our slowed development pace. We scaled back our development program due to lower liquidity and operating cash flow, as a result of the lower price environment relative to December 31, 2019. These revisions do not represent the elimination of recoverable hydrocarbons physically in place, as they may be developed in the future.

Independent Reserve Engineers

Our reserve estimates are calculated by Ryder Scott as of December 31, ~~2019~~2020 in accordance with SEC guidelines. The reserve estimates are based on, and fairly represent, information and supporting documentation prepared by, or under supervision of Mr. Stephen E. Gardner. Mr. Gardner is a Licensed Professional Engineer in the States of Colorado (Colorado No. 44720) and Texas (Texas No. 100578) with over 1415 years of practical experience in estimation and evaluation of petroleum reserves. Mr. Gardner meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We believe that he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. Mr. Gardner consents to the inclusion in this report of the information and context in which it appears.

Internal Controls over Reserves Estimation Process

The primary inputs into the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. Our technical team consists of an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates.

Our board of directors has also established a Reserves Committee to assist with monitoring (i) the integrity of our oil, natural gas, and NGL reserves, (ii) the independence, qualifications and performance of our independent reservoir engineers, and (iii) our compliance with legal and regulatory requirements. Prior to release of the reserve report prepared by our independent reserve engineers, the draft of the report is reviewed by the Reserves Committee, our internal petroleum engineers and management.

7 9

Table of Contents

Our senior reservoir engineer is the technical person primarily responsible for overseeing the preparation of our internal reserves estimates and year-end third-party report of our reserves estimates. He received his Masters of Science and Ph.D. in Petroleum Engineering from the Colorado School of Mines. He is also a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers. The senior reservoir engineer currently reports directly to our Chief ~~Executive~~Operating Officer.

Technology Used to Establish Estimates of Proved Reserves

Under SEC rules, proved reserves are those quantities of oil and natural gas that 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, under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, Ryder Scott employed or reviewed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data, well test data, simulation, and statistical methods. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using both volumetric estimates and performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Acreage

~~We had the following developed, undeveloped and total acres as of December 31, 2019:~~

Developed

Undeveloped

Total

Gross

Net

Gross

Net

Gross

Net

Eagle Ford (1)

21,869

19,652

35,501

26,776

57,370

46,428

We had the following developed, undeveloped and total acres as of December 31, 2020:

~~(1) Includes 1,573 gross (1,438 net) developed acres and 7,617 gross (3,808 net) undeveloped acres located in Texas, targeting non Eagle Ford formations.~~

Developed

Undeveloped

Total

Gross

Net

Gross

Net

Gross

Net

Eagle Ford (1)

16,844

14,732

36,308

27,720

53,152

42,452

(1)

Includes 7,617 gross (3,808 net) undeveloped acres located in Texas, targeting non-Eagle Ford formations.

Most of our undeveloped leasehold acreage is currently held by production and not subject to expiration. Approximately 4,500 net acres is currently held by production, but may be subject to future drilling obligations at certain oil prices.

Table of Contents

Production and Pricing

The following tables set forth information regarding our total production and average daily production for the periods indicated from our operating areas:

	Year ended December 31,
	2019		2018		2017
Net Sales Volumes:
Oil (MBbls)		3,076.6		2,256.0		1,799.8
Natural gas (MMcf)		5,767.8		4,533.6		3,621.3
NGL (MBbls)		797.8		496.6		323.7
Oil equivalent (MBoe)		4,835.7		3,508.2		2,727.0
Average daily volumes (Boe/d)		13,248		9,612		7,471
Average Sales Price
Oil (per Bbl)	$	57.81	$	62.16	$	49.53
Natural gas (per Mcf)		2.18		2.65		2.41
NGL (per MBbls)		16.51		25.51		20.14
Average equivalent price (per Boe)		42.10		47.01		38.28
Expenses (per Boe):
Lease operating and workover expense	$	6.96	$	9.68	$	8.22
Gathering, processing and transportation expense		3.53		2.46		-
Production tax expense		2.37		2.64		2.30
Total operating expenses	$	12.86	$	14.78		10.52


	Year ended December 31,
	2020		2019		2018
Net Sales Volumes:
Oil (MBbls)		2,104.8		3,076.6		2,256.0
Natural gas (MMcf)		3,969.0		5,767.8		4,533.6
NGL (MBbls)		539.8		797.8		496.6
Oil equivalent (MBoe)		3,306.1		4,835.7		3,508.2
Average daily volumes (Boe/d)		9,033		13,248		9,612
Average Sales Price
Oil (per Bbl)	$	36.36	$	57.81	$	62.16
Natural gas (per Mcf)		1.99		2.18		2.65
NGL (per MBbls)		13.69		16.51		25.51
Average equivalent price (per Boe)		27.77		42.10		47.01
Expenses (per Boe):
Lease operating and workover expense	$	7.62	$	6.96	$	9.68
Gathering, processing and transportation expense ⁽¹⁾		6.15		3.53		2.46
Production tax expense		1.65		2.37		2.64
Total operating expense	$	15.42	$	12.86	$	14.78

(1)

Includes minimum revenue commitment deficiency fees of $2.42, $0.49, and $0.79 per Boe for the years ended December 31, 2020, 2019 and 2018, respectively.

Producing Wells

~~We had the following producing wells as of December 31, 2019:~~

Natural Gas

Oil Wells

Wells

Total Wells

Gross

Net

Gross

Net

Gross

Net

Eagle Ford

244.0

215.0

2.5

255.0

217.5

We had the following producing wells as of December 31, 2020:

Natural Gas

Oil Wells

Wells

Total Wells

Gross

Net

Gross

Net

Gross

Net

Eagle Ford

253.0

222.6

2.5

264.0

225.1

Drilling Activity

~~The following table summarizes our drilling activity for the fiscal years ended December 31, 2019, 2018 and 2017:~~

	Year ended December 31,
	2019		2018		2017
	Gross	Net	Gross	Net	Gross	Net
Development wells
Oil	27	22.3	23	23.0	14	13.8
Natural Gas	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total Wells	27	22.3	23	23.0	14	13.8

The following table summarizes our drilling activity for the fiscal years ended December 31, 2020, 2019 and 2018:

We did not drill any exploratory wells during the years ended December 31, 2019, 2018 and 2017. As of December 31, 2019, we had 2 gross (2.0 net) wells waiting on completion and 3 gross (0.3 net) non-operated wells were being drilled.


	Year ended December 31,
	2020		2019		2018
	Gross	Net	Gross	Net	Gross	Net
Development wells
Oil	11	8.2	27	22.3	23	23.0
Natural Gas	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total Wells	11	8.2	27	22.3	23	23.0

We did not drill any exploratory wells during the years ended December 31, 2020, 2019 and 2018.

Table of Contents

Operations

General

We operated 97% of our production for the year ended December 31, 2019. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis.

We operated 95% of our production for the year ended December 31, 2020. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis.

Marketing and Customers

For the year ended December 31, 2019, purchases by two customers each accounted for over 10% of our total sales revenues. Our largest customer, a large midstream company and production purchaser accounted for approximately 60% of our 2019 revenue. We have a long-term contract in place with this customer, under which we are subject to minimum revenue commitments (“MRCs”) for gathering, processing, transportation and marketing services, with $54.3 million remaining through 2022 (described more below in Part I, Item 1. “Business” under “Delivery Commitments”). Our second largest customer, a large physical trading and logistics company, accounted for approximately 21% of our 2019 revenue. Our agreement with this purchaser ended in September 2019, and was replaced by a marketing agreement with another large physical trading company.

For the year ended December 31, 2020, purchases by two customers each accounted for over 10% of our total sales revenues. Our largest customer, a large midstream company and production purchaser accounted for approximately 66% of our 2020 revenue. We have a long-term contract in place with this customer, under which we are subject to minimum revenue commitments (“MRCs”) for gathering, processing, transportation and marketing services, with $32.2 million remaining through 2022 (described more below in Part I, Item 1. “Business” under “Delivery Commitments”). Our second largest customer, a large physical trading and logistics company, accounted for approximately 22% of our 2020 revenue. Our agreement with this purchaser ended on December 31, 2020, and was replaced by a marketing agreement with another large physical trading company.

The oil and natural gas that we sell are commodities for which there are a large number of potential buyers. Because of the adequacy of the infrastructure to transport oil and natural gas in the areas in which we operate, if we were to lose one or more customers, we believe that we could readily procure substitute or additional customers such that our production volumes would not be materially affected for any significant period of time.

The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include global economic and political conditions, the level of demand for oil and natural gas, the price and quantity of imports of foreign oil and natural gas, the level of global oil and natural gas exploration and production, global oil and gas inventories, weather conditions and natural disasters, the outbreak of pandemic or contagious disease, governmental regulations, oil and natural gas speculation, actions of the Organization of Petroleum Exporting Companies (“OPEC”), technological advances and the price and availability of alternative fuels. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months.

Delivery Commitments

In conjunction with our 2018 acquisition, we entered into contracts with a large midstream company to provide gathering, processing, transportation and marketing of hydrocarbon production for the acquired properties. The contracts contain MRCs that requires us to pay minimum annual fees related to gathering, processing, transportation and marketing. Volumetric fixed fees are expensed as incurred and settled with the midstream company on a monthly basis. The following table summarizes the remaining MRC (in thousands) by year:

	Year ending December 31,
	2020		2021		2022		Total
Hydrocarbon gathering and handling agreement	$	14,297	$	13,972	$	6,675	$	34,944
Crude oil and condensate purchase agreements		4,710		7,513		4,317		16,540
Gas processing agreement		2,017		-		-		2,017
Gas transportation agreements		783		-		-		783
Total MRC	$	21,807	$	21,485	$	10,992	$	54,284



	2021		2022		Total
Hydrocarbon gathering and handling agreement	$	13,925	$	6,541	$	20,466
Crude oil and condensate purchase agreements		7,488		4,230		11,718
Total MRC	$	21,413	$	10,771	$	32,184

Table of Contents

If, at the end of any calendar year during the term of the contract, we fail to satisfy our MRC with the monthly settlements paid during the year, we are required to pay a deficiency payment equal to the shortfall. If the volumes and associated fees exceed the MRC in any contractual year, the overage can be applied to reduce the future shortfalls, if any.

The MRC for the years ended December 31, 2019 and 2018 totaled $15.8 million and $11.1 million, respectively, and we realized a shortfall of $2.3 million and $2.8 million, respectively. Based on our 2019 development plan, we had anticipated an immaterial MRC shortfall, however, midstream constraints reduced our sales volumes, and increased the amount of the 2019 shortfall. The 2018 commitment was measured on a calendar year basis; however, we did not own and operate the acquired assets until April 23, 2018. Due to the timing of the acquisition, our development program was back-loaded in 2018, and we were unable to meet the 2018 MRC.

Current production from the producing wells dedicated under these agreements is not sufficient to meet the MRC for the hydrocarbon gathering and handling agreement~~. Based~~ onand ~~our current 2020 development plan,~~ we ~~expect we will~~ have arealized ~~shortfall~~shortfalls under the hydrocarbon gathering and handling agreement ~~for~~in ~~the~~2018, ~~year~~2019 ~~ending~~and ~~December 31,~~ 2020. Our ability to meet our commitments in future periods will depend on our pace of development through the term of the contract. Our development plan is subject to a number of risks, many of which are not within our control.

Competition

The oil and natural gas industry is highly competitive, and we compete with a substantial number of other companies that have greater resources than we do. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties and obtaining drilling rigs, completion crews and other services. Our competitors may be able to pay more for productive crude oil and natural gas properties and undeveloped prospects, or bid for and purchase a greater number of properties and prospects than our financial resources permit.

There is also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by state, local and the U.S. government agencies. However, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to better absorb the burden of existing and changing federal, state or local laws and regulations than we can, which would adversely impact our competitive position.

Seasonality of Business

We do not believe that the pricing of our crude oil and NGL production is subject to any meaningful seasonal effects. Historically, the pricing of natural gas is seasonal, typically with higher pricing in the winter months.

Title to Properties

Title to our properties are subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of properties or from the respective interests therein or materially interfere with their use in the operation of our business.

As is customary in the industry, a preliminary title investigation, typically consisting of a review of local title records, is made at the time of acquisitions of undeveloped properties. More thorough title investigations, which generally include a review of title records and the preparation of title opinions by outside legal counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

Table of Contents

Government Regulations

Nearly every aspect of our business is subject to expansive federal, state, and local laws and governmental regulations. These laws and regulations frequently change in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations have the potential to increase our cost of doing business and consequently could affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry.

Regulation of Production

The State of Texas, the state where we conduct operations and own nearly all of our oil and gas assets, has adopted laws and regulations governing the exploration for and production of oil, gas, and NGLs, including laws and regulations requiring permits for the drilling of wells, imposing bond requirements in order to drill or operate wells, governing the timing of drilling and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to Texas conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the unitization or pooling of oil and gas properties. In addition, Texas conservation laws establish maximum rates of production from oil and gas wells, generally limit or prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Our sales of gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of gas in interstate commerce. FERC’s current regulatory framework generally provides for a competitive and open access market for sales and transportation of gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for gas production.

Environmental, Health and Safety Matters

Oil, natural gas and NGL exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, including requirements to:

·● obtain permits to conduct regulated activities;

·● limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

·● restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling and production activities;

·● initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells;

·● apply specific health and safety criteria addressing worker protection; and

·● impose substantial liabilities for pollution resulting from operations.

Table of Contents

Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of strict, joint and several liability, investigatory and remedial obligations and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. Moreover, these laws, rules and regulations may restrict the rate of oil, natural gas and NGL production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could increase the cost of developing our properties. Moreover, accidental releases or spills may occur in the course of operations on our properties, causing our operators to incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

Uncertainty about the future course of regulation exists because of the recent change in U.S. presidential administrations. In January 2021, the current administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions promulgated during the prior administration that may be inconsistent with the administration’s policies. As a result, it is unclear the degree to which certain recent regulatory developments may be modified or rescinded. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases (“Working Group”), which is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” Recommendations from the Working Group are due beginning June 1, 2021, and final recommendations no later than January 2022. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas. Also in January 2021, the current administration issued an executive order focused on addressing climate change. Among other things, that executive order directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The executive order also directs the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. Legal challenges to the suspension have already been filed and are currently pending.

Increased costs or operating restrictions on our properties as a result of compliance with environmental laws could result in reduced exploratory and production activities on our properties and, as a result, our revenues and results of operations. The following is a summary of certain existing environmental, health and safety laws and regulations, each as amended from time to time, to which operations on our properties are subject.

Hazardous Substances and Waste

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. CERCLA exempts “petroleum, including oil or any fraction thereof” from the definition of “hazardous substance” unless specifically listed or designated under CERCLA. While the Environmental Protection Agency (“EPA”) interprets CERCLA to exclude oil and fractions of oil, hazardous substances that are added to petroleum or that increase in concentration as a result of contamination of the petroleum during use are not considered part of the petroleum and are regulated under CERCLA as a hazardous substance. Comparable state statutes may include petroleum in the definition of hazardous substance.

Table of Contents

Responsible persons under CERCLA include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances under CERCLA.

We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. RCRA imposes requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations, we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes under RCRA. RCRA regulations specifically exclude from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy.” However, legislation has been proposed in the U.S. Congress from time to time that would reclassify certain oil and natural gas exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and cleanup requirements. No such effort has been successful to date.

Table of Contents

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including groundwater contaminated by prior owners or operators) and to perform remedial operations to prevent future contamination.

Air Emissions

The Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the emission of air pollutants, including greenhouse gases, from many sources, including oil and natural gas operations, and impose various monitoring and reporting requirements. These laws and regulations may require us to obtain preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements, report emissions, or utilize specific equipment or technologies to control emissions. CAA rules may require us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment and implementing additional emissions testing and monitoring. These requirements have the potential to delay or increase the cost of the development of oil and natural gas projects. Moreover, changes in environmental laws and regulations occur frequently, and stricter laws, regulations or enforcement policies could significantly increase our compliance costs or negatively impact our production and operations. For example, in 2015, the EPA released a final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion (“ppb”) to 70 ppb. If areas in which we operate are designated as nonattainment or if the EPA were to further reduce ozone standards, bringing areas in which we operate into nonattainment, states that contain any areas designated nonattainment, and any tribes that choose to do so, are required to develop state implementation plans demonstrating how the area will attain the standard within a prescribed period of time. These plans may require the installation of additional equipment to control emissions. Similar initiatives could lead to more stringent air permitting, increased regulation and possible enforcement actions at the local, state, and federal levels.

~~Additionally~~The Clean Air Act, ~~the~~as ~~EPA~~amended ~~has~~(“CAA”), ~~established~~and ~~new~~comparable ~~air~~state laws and regulations restrict the emission ~~control~~of ~~requirements~~air ~~for~~pollutants, ~~oil~~including greenhouse gases, from many sources, including oil and natural gas operations, and ~~NGLs~~impose ~~production,~~various ~~processing~~monitoring and ~~transportation~~reporting ~~activities,~~requirements. ~~including~~These ~~New~~laws ~~Source~~and ~~Performance~~regulations ~~Standards~~may ~~(“NSPS”)~~require us to ~~address~~obtain ~~emissions~~preapproval for the construction or modification of ~~sulfur~~certain ~~dioxide~~projects ~~and~~or ~~volatile~~facilities ~~organic~~expected ~~compounds~~to produce or significantly increase air emissions, obtain and ~~National~~comply ~~Emission~~with ~~Standards~~stringent ~~for~~air ~~Hazardous~~permit ~~Air~~requirements, ~~Pollutants~~report ~~(“NESHAPS”)~~emissions, or utilize specific equipment or technologies to ~~address~~control ~~hazardous~~emissions. ~~air~~CAA ~~pollutants~~rules may ~~frequently~~require ~~associated~~us ~~with~~to ~~gas~~undertake ~~production~~certain expenditures and ~~processing~~ activities, including purchasing and installing emissions control equipment and implementing additional emissions testing and monitoring. ~~Among~~These ~~other~~requirements ~~things,~~have ~~these~~the ~~rules~~potential ~~require~~to delay or increase the ~~reduction~~cost of ~~volatile~~the ~~organic~~development ~~compound~~of ~~emissions~~oil ~~from~~and natural gas ~~wells~~projects. ~~through~~Moreover, ~~the~~changes ~~use~~in ofenvironmental ~~reduced~~laws ~~emission~~and ~~completions~~regulations occur frequently, and stricter laws, regulations or ~~“green~~enforcement ~~completions”~~policies oncould ~~all~~significantly ~~hydraulically~~increase ~~fractured~~our ~~wells~~compliance ~~constructed~~costs or ~~refractured~~negatively ~~after~~impact ~~January~~our 1,production ~~2015~~and operations. InFor ~~addition~~example, ~~gas~~in ~~wells~~2015, ~~are~~the ~~required~~EPA toreleased ~~use~~a ~~completion~~final ~~combustion~~rule ~~device~~tightening ~~equipment~~the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion (i“ppb”) to 70 ppb.e. In December 2018 and again in December 2020, ~~flaring)~~the byEPA ~~October~~announced 15that it was retaining without revision the 2015 NAAQS ozone standard. However, ~~2012~~in January 2021, ifthe ~~emissions~~Biden ~~cannot~~administration beissued ~~directed~~an executive order calling on the EPA to, among other things, propose a ~~gathering~~Federal ~~line.~~Implementation ~~Further~~Plan for ozone standards for California, ~~the~~Connecticut, ~~final~~New ~~rules~~York, ~~under~~Pennsylvania ~~NESHAPS~~and ~~include~~Texas ~~maximum~~by ~~achievable~~January ~~control~~2022. ~~technology~~If areas in which we operate are designated as nonattainment or if the EPA were to further reduce ozone standards, ~~for~~bringing ~~“small”~~areas ~~glycol~~in ~~dehydrators~~which we operate into nonattainment, states that contain any areas designated nonattainment, and any tribes that choose to do so, are ~~located~~required atto ~~major~~develop ~~sources~~state implementation plans demonstrating how the area will attain the standard within a prescribed period of ~~hazardous~~time. These plans may require the installation of additional equipment to control emissions. Similar initiatives could lead to more stringent air ~~pollutants~~permitting, increased regulation and ~~modifications~~possible toenforcement actions at the ~~leak~~local, ~~detection~~state, ~~standards~~and ~~for~~federal ~~valves~~levels.

14 16

Table of Contents

~~In 2016~~Additionally, the EPA ~~published~~has ~~updates~~established to new ~~source~~air ~~performance~~emission ~~standard~~control requirements ~~that~~for ~~would~~oil, ~~impose~~natural ~~more~~gas ~~stringent controls on methane~~ and ~~volatile~~NGLs ~~organic~~production, ~~compounds~~processing ~~emissions from oil~~ and ~~gas~~transportation ~~development and production operations~~activities, including ~~hydraulic~~New ~~fracturing~~Source ~~and~~Performance ~~other~~Standards ~~well~~(“NSPS”) ~~completion~~to ~~activity.~~address ~~Many~~emissions of ~~these~~sulfur ~~requirements~~dioxide ~~were~~and ~~rescinded~~volatile inorganic acompounds, ~~proposed~~and ~~rule~~National ~~published~~Emission byStandards ~~the~~for ~~EPA~~Hazardous inAir ~~August~~Pollutants ~~2019,~~(“NESHAPS”) ~~which~~to ~~has~~address ~~not~~hazardous ~~yet~~air ~~been~~pollutants ~~finalized.~~frequently ~~However,~~associated ~~the~~with ~~2016~~gas ~~rule~~production ~~currently~~and ~~remains~~processing ~~in effect~~activities. ~~Similarly~~Among inother ~~November 2016~~things, ~~the~~these ~~Bureau~~rules ofrequire ~~Land~~the ~~Management~~reduction ~~(“BLM”)~~of ~~issued~~volatile ~~rules~~organic ~~requiring~~compound ~~additional~~emissions ~~efforts~~from bynatural ~~producers~~gas towells ~~reduce~~through ~~venting,~~the ~~flaring,~~use ~~and~~of ~~leaking~~reduced ofemission ~~natural~~completions ~~gas~~or ~~produced~~“green completions” on ~~federal~~all ~~and~~hydraulically ~~Native~~fractured ~~American~~wells ~~lands,~~constructed ~~though~~or ~~many~~refractured ofafter ~~these~~January ~~regulations~~1, ~~were~~2015. ~~later~~In ~~rescinded~~addition, bygas awells ~~final~~are ~~rule~~required ~~published~~to byuse ~~the~~completion ~~BLM~~combustion indevice ~~September~~equipment ~~2018~~(i.e., ~~Compliance~~flaring) ~~with~~by ~~these~~October or15, ~~other~~2012, ~~future~~if ~~changes~~emissions tocannot ~~regulations~~be ~~regarding~~directed ~~air emission may require modifications~~ to ~~certain~~a ofgathering ~~our~~line. ~~operations~~Further, ~~including~~ the ~~installation~~final ofrules ~~new~~under ~~equipment~~NESHAPS toinclude maximum achievable control ~~emissions~~technology atstandards ~~the~~for ~~well~~“small” ~~site~~glycol dehydrators that ~~could~~are ~~result~~located inat ~~significant~~major ~~costs,~~sources ~~including~~of ~~increased~~hazardous ~~capital~~air ~~expenditures~~pollutants and ~~operating~~modifications ~~costs,~~to ~~and~~the ~~could~~leak ~~adversely~~detection ~~impact~~standards ~~our~~for ~~business~~valves.

In 2012 and 2016, the EPA adopted various regulations specific to oil and gas exploration, production, gathering and processing, which impose air quality controls and work practices, and govern source determination and permitting requirements, as well as methane emissions. In September 2018, the EPA announced proposed revisions to the various regulations which may reduce compliance burdens on some facilities. In August 2020 EPA adopted deregulatory amendments to the 2016 rule intended to streamline implementation, reduce duplicative EPA and state requirements and decrease the burden of compliance. In particular, the amendments removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. Several lawsuits were filed challenging these amendments, and the U.S. Court of Appeals for the D.C. Circuit ordered an administrative stay of these amendments shortly after they were finalized. Although the administrative stay was lifted in October 2020, which brought the amendments into effect, the amendments may still be subject to reversal under the current presidential administration. In January 2021, the administration issued an executive order calling on the EPA to, among other things, consider a proposed rule suspending, revising or rescinding the deregulatory amendments by September 2021.

Similarly, in November 2016, the Bureau of Land Management (“BLM”) issued rules requiring additional efforts by producers to reduce venting, flaring, and leaking of natural gas produced on federal and Native American lands, though many of these regulations were later rescinded by a final rule published by the BLM in September 2018. Compliance with these or other future changes to regulations regarding air emission may require modifications to certain of our operations, including the installation of new equipment to control emissions at the well site that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

Climate Change

~~The~~ U.S. is a party to the United Nations Framework Convention on Climate Change, an international treaty focused on stabilizing greenhouse gas (“GHG”) concentrations in the atmosphere at a level that would prevent serious damage to the climate system. In December 2015, the international community agreed upon a new climate change treaty, known as the Paris Agreement. The U.S. committed to a 26-28% reduction in its GHG emissions by 2025 against a 2005 baseline. This new agreement, which was legally effective in November 2016, incorporates actions taken by individual countries to reduce GHG on the national level. U.S. involvement in developing the new agreement creates significant international pressure for the U.S. to take responsive action to reduce GHG emissions. President Trump stated in June 2017 that he intends to withdraw the U.S. from the Paris Agreement and in November 2019, the U.S. submitted formal notification of its withdrawal from the Paris Agreement to the United Nations. Under the terms of the Paris Agreement, the earliest the U.S. could withdraw from the treaty is November 2020. The Trump administration may allow the U.S. to remain in the Paris Agreement, but soften the emission reductions that the U.S. implements to comply with the Paris Agreement. In general, implementation of the Paris Agreement would encourage a shift away from higher GHG emitting power sources like coal-fired power plants.

The U.S. is a party to the United Nations Framework Convention on Climate Change, an international treaty focused on stabilizing greenhouse gas (“GHG”) concentrations in the atmosphere at a level that would prevent serious damage to the climate system. In December 2015, the ~~absence~~international ofcommunity ~~comprehensive~~agreed upon a new climate change ~~legislation~~treaty, ~~regulatory~~known ~~action~~as the Paris Agreement. The U.S. committed to a ~~regulate~~26-28% reduction in its GHG emissions ~~under~~by ~~the~~2025 ~~federal~~against ~~Clean~~a ~~Air~~2005 ~~Act~~baseline. ~~occurred~~This ~~under~~new agreement, which was legally effective in November 2016, incorporates actions taken by individual countries to reduce GHG on the ~~Obama~~national ~~administration~~level. ~~The~~U.S. ~~Trump~~involvement ~~administration~~in isdeveloping inthe new agreement creates significant international pressure for the ~~process~~U.S. ofto ~~narrowing~~take responsive action to reduce GHG emissions. In November 2019, ~~revising~~during orthe ~~attempting~~Trump toadministration, ~~repeal~~the ~~nearly~~U.S. ~~all~~submitted formal notification of its withdrawal from the ~~Obama-era~~Paris ~~climate~~Agreement ~~regulations.~~to ~~Thus~~the United Nations, noeffective ~~new~~November ~~federal~~2020. However, ~~climate~~the ~~regulations~~executive ~~that~~order ~~impose~~issued ~~additional~~by ~~requirements~~the ~~are~~Biden ~~likely~~administration in ~~the~~January ~~near~~2021 ~~term~~commenced inthe process for the U.S. ~~and~~reentering the ~~focus~~Paris ~~will~~Climate beAgreement, onalthough the ~~state~~emissions ~~level~~pledges in connection with ~~certain~~that ~~states~~effort ~~like~~have ~~California~~not ~~taking~~yet ~~significant~~been ~~actions~~updated. toIn ~~reduce~~general, implementation of the Paris Agreement would encourage a shift away from higher GHG ~~emissions~~emitting power sources like coal-fired power plants.

The EPA requires the reporting of GHG emissions from specified large GHG emission sources, including GHG from petroleum and natural gas systems that emit more than 25,000 tons of GHG per year. Reporting is required from onshore and offshore petroleum and natural gas production, natural gas processing, transmission and distribution, underground natural gas storage and liquefied natural gas import, export and storage.

Table of Contents

In ~~2017,~~the ~~President~~absence ~~Trump~~of ~~signed~~comprehensive ~~an executive order to rescind President Obama’s~~ climate~~-related~~ ~~executive~~change ~~orders~~legislation, ~~and~~regulatory ~~climate~~ action ~~plans and~~ to ~~direct~~regulate ~~the~~GHG ~~EPA~~emissions tounder ~~review~~the ~~and~~federal ~~revise~~Clean ~~the~~Air ~~Clean~~Act ~~Power~~occurred ~~Plan,~~under the ~~standards~~Obama ~~for new power plants and other climate regulations~~administration. The ~~executive~~Trump ~~order~~administration ~~sets~~was in ~~motion~~the a process ~~that~~of ~~will~~narrowing, ~~take~~revising ~~several~~or ~~years~~attempting to ~~fully~~repeal ~~implement.~~nearly ~~Because~~all of the ~~EPA~~Obama-era climate regulations. ~~are final regulations~~However, ~~the~~as ~~EPA~~mentioned ~~will~~above, ~~have~~in toJanuary go2021, ~~through~~the aBiden ~~notice~~administration ~~and~~issued ~~comment~~an ~~rulemaking~~executive ~~process~~order todirecting ~~modify~~all orfederal ~~revoke~~agencies ~~them~~to review and ~~such~~take ~~actions~~action ~~are~~to ~~expected~~address toany befederal ~~litigated~~regulations, byorders, ~~environmental~~guidance ~~groups~~documents, policies and ~~states~~any ~~supportive~~similar ofagency ~~the~~actions ~~regulations.~~promulgated ~~Even~~during if the ~~carbon~~prior ~~regulations~~administration ~~are~~that ~~ultimately~~may ~~revoked~~be orinconsistent ~~weakened~~with ~~under~~ the ~~Trump~~current administration’s policies. As a result, weit ~~may~~is ~~continue~~unclear tothe ~~incur~~degree ~~compliance~~to ~~costs~~which ~~and~~certain werecent ~~may~~regulatory ~~incur~~developments ~~new~~undertaken ~~costs~~during ~~associated~~the ~~with~~Trump ~~transitioning~~administration tomay ~~the~~be ~~new~~modified ~~requirements.~~or rescinded.

The EPA’s ~~GHG~~requires ~~rules are being reviewed pursuant to President Trump’s executive order and many are being challenged in court proceedings. Depending on~~ the ~~outcome~~reporting of ~~such~~GHG ~~proceedings,~~emissions ~~the~~from ~~rules may~~specified belarge ~~modified~~GHG oremission ~~rescinded~~sources, orincluding ~~the~~GHG ~~EPA~~from ~~could~~petroleum ~~develop new rules. The adoption~~ and ~~implementation~~natural ofgas ~~any~~systems ~~regulations~~that ~~imposing~~emit ~~reporting~~more ~~obligations~~than on25,000 ortons ~~limiting emissions~~ of GHG ~~from,~~per ~~our~~year. ~~equipment~~Reporting ~~and~~is ~~operations~~required ~~could~~from ~~require~~onshore usand tooffshore ~~incur~~petroleum ~~costs~~and tonatural ~~reduce~~gas ~~emissions~~production, ofnatural ~~GHG~~gas ~~associated~~processing, ~~with~~transmission ~~our~~and ~~operations~~distribution, orunderground ~~could~~natural ~~adversely~~gas ~~affect~~storage ~~demand for the oil~~ and liquefied natural gas weimport, ~~produce~~export and storage.

While new legislation requiring GHG controls is not expected at the national level in the near term, almost one-half of the states have taken actions to monitor and/or reduce emissions of GHG, including obligations on utilities to purchase renewable energy and participate in GHG cap and trade programs. Although most of the state level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future.

In 2015, the EPA released the final Clean Power Plan, which is a regulation designed to reduce carbon pollution from existing fossil fuel-fired power plants, including natural gas power plants. Upon finalization of the Clean Power Plan, over twenty states and industry groups challenged the rule in the D.C. Circuit court and requested a stay of the rule. In 2019, the EPA replaced the Clean Power Plan with the more narrowly-scoped Affordable Clean Energy rule. The rule was challenged by public health groups, certain states and environmental groups, and in January 2021, the D.C. Circuit Court of Appeals vacated the Affordable Clean Energy rule and its implied repeal of the Clean Power Plan, remanding to EPA for further proceedings. In the event the matter is not heard by the Supreme Court, it is not clear whether EPA will reinstate the Clean Power Plan or undertake new rulemaking.

In 2016, the EPA issued a suite of proposed regulations that would reduce methane emissions from the oil and gas industry, including proposed updates to the NSPS for new and modified sources in the oil and gas industry, a clarification of the source determination rule as applied to the oil and natural gas industry and a proposed Federal Implementation Plan for new oil and gas sources in Indian Country. These regulations could affect us indirectly by affecting our customer base or by directly regulating our operations. In either case, increased costs of operation and exposure to liability could result. In 2019, the EPA proposed to replace existing NSPS methane limits with a narrower rule and to amend the Federal Implementation Plan for oil and gas production activities in Indian Country. In August 2020, the EPA adopted deregulatory amendments to the 2016 rule intended to streamline implementation, reduce duplicative EPA and state requirements and decrease the burden of compliance. In particular, the amendments removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. In January 2021, the administration issued an executive order calling on the EPA to, among other things, consider a proposed rule suspending, revising or rescinding the deregulatory amendments by September 2021. Accordingly, the EPA is currently reviewing rule and its future implementation is uncertain at this time.

In addition to activity at the federal level, almost one-half of the states have taken actions to monitor and/or reduce emissions of GHG, including obligations on utilities to purchase renewable energy and participate in GHG cap and trade programs. Although most of the state level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future.

Climate change regulatory and legislative initiatives could have a material adverse effect on our business, results of operations and financial condition. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, such as coal, our products could become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources, such as solar and wind, our products could become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Table of Contents

Finally, increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. Such effects could adversely affect or delay demand for the oil or natural gas we produce or otherwise cause us to incur significant costs in preparing for or responding to those effects.

Water Discharges

The Federal Water Pollution Control Act, as amended, or the Clean Water Act (“CWA”), and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the U.S. Pursuant to the CWA and analogous state laws, permits must be obtained from the EPA or analogous state agency to discharge pollutants into state waters or waters of the U.S. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities. Currently, storm water discharges from oil and natural gas exploration, production, processing or treatment operations, or transmission facilities are exempt from regulation under the CWA. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as other enforcement mechanisms for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Table of Contents

Endangered Species Act

The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Employee Health and Safety

We are subject to a number of federal and state laws and regulations regulating employee health and safety, including the federal Occupational Safety and Health Act, as amended (the “OSH Act”), and comparable state statutes. In addition, the OSH Act’s hazard communication standard, the EPA’s “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used, produced or released in our operations and that this information be provided to employees, state and local government authorities and the public. OSH Act regulates worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. The key provisions of the rule: (i) reduce the permissible exposure limit (PEL) for respirable crystalline silica to 50 micrograms per cubic meter of air, averaged over an 8‑hour shift; (ii) require employers to: use engineering controls (such as water or ventilation) to limit worker exposure to the PEL; provide respirators when engineering controls cannot adequately limit exposure; limit worker access to high exposure areas; develop a written exposure control plan, offer medical exams to highly exposed workers, and train workers on silica risks and how to limit exposures; (iii) provide medical exams to monitor highly exposed workers and gives them information about their lung health; and (iv) provide flexibility to help employers protect workers from silica exposure. Workers at well sites may be exposed to excessive levels of respirable silica sand, which can cause lung disease and cancer. Increasing concerns about worker safety at well sites may lead to increased regulation and enforcement or related tort claims by our employees. Implementation of engineering and workplace controls to comply with the rule may require significant investment.

We are subject to a number of federal and state laws and regulations regulating employee health and safety, including the federal Occupational Safety and Health Act, as amended (the “OSH Act”), and comparable state statutes. In addition, the OSH Act’s hazard communication standard, the EPA’s “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used, produced or released in our operations and that this information be provided to employees, state and local government authorities and the public. The OSH Act regulates worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. The key provisions of the rule are to: (i) reduce the permissible exposure limit (“PEL”) for respirable crystalline silica to 50 micrograms per cubic meter of air, averaged over an 8-hour shift; (ii) require employers to: use engineering controls (such as water or ventilation) to limit worker exposure to the PEL; provide respirators when engineering controls cannot adequately limit exposure; limit worker access to high exposure areas; develop a written exposure control plan, offer medical exams to highly exposed workers, and train workers on silica risks and how to limit exposures; (iii) provide medical exams to monitor highly exposed workers and gives them information about their lung health; and (iv) provide flexibility to help employers protect workers from silica exposure. Workers at well sites may be exposed to excessive levels of respirable silica sand, which can cause lung disease and cancer. Increasing concerns about worker safety at well sites may lead to increased regulation and enforcement or related tort claims by our employees. Implementation of engineering and workplace controls to comply with the rule may require significant investment.

Table of Contents

Hydraulic Fracturing

The Safe Drinking Water Act (“SDWA”) and comparable state statutes may restrict the disposal, treatment or release of water produced or used during oil and natural gas development. Subsurface emplacement of fluids (including disposal wells) is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory authority or the state’s environmental authority. We utilize hydraulic fracturing in our operations as a means of maximizing the productivity of our wells and operate saltwater disposal wells to dispose of produced water. The federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the SDWA to expressly exclude hydraulic fracturing without diesel additives from the definition of “underground injection.” However, the U.S. Senate and House of Representatives have considered several bills in recent years to end this exemption, as well as other exemptions for oil and gas activities under U.S. environmental laws. The Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”), first introduced in 2011, would amend the SDWA to repeal the exemption from regulation under the UIC program for hydraulic fracturing. This bill has been reintroduced in each congressional session since it was initially proposed but has not yet garnered enough support to be put to a vote. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, to adhere to certain construction specifications, to fulfill monitoring, reporting and recordkeeping obligations and to meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process. Note that each of the above components of the FRAC Act have become increasingly common in state laws since the FRAC Act was first introduced. Other bills that have been introduced in recent years in the U.S. House of Representatives would end certain exemptions for oil and natural gas operations related to permitting requirements for multiple commonly owned and adjacent sources of hazardous air pollutants under the CAA and permitting requirements for stormwater discharges under the CWA. If the exemptions for hydraulic fracturing are removed from U.S. environmental laws, or if the FRAC Act or other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operations.

Federal agencies have also begun to directly regulate hydraulic fracturing. The EPA has asserted federal regulatory authority over, and issued permitting guidance for, hydraulic fracturing involving diesel additives under the SDWA’s UIC Program. As a result, service providers or companies that use diesel products in the hydraulic fracturing process are expected to be subject to additional permitting requirements or enforcement actions under the SDWA. The EPA has promulgated pretreatment standards for oil and gas extraction category under the CWA that prohibit the discharge of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly owned treatment works. The EPA also has been conducting a study of private wastewater treatment facilities accepting oil and gas extraction wastewater. The EPA collected data and information related to the extent to which such wastewater is accepted, available treatment technologies, discharge characteristics and other information. The EPA is currently reviewing comments on the draft study report. The use of surface impoundments (i.e., pits or surface storage tanks) for the temporary storage of hydraulic fracturing fluids for re-use or prior to disposal may also be regulated. The EPA also completed a multi-year study about the effects of hydraulic fracturing on drinking water. Although the regulations for hydraulic fracturing on federal land that were promulgated by the U.S. Department of the Interior in 2015 were rescinded in 2017, that 2017 rulemaking is the subject of ongoing litigation. These regulatory developments have the potential to create additional permitting, technology, recordkeeping and site study requirements, among others, for our business.

Table of Contents

Several state governments in the areas where we operate have adopted or are considering adopting additional requirements relating to hydraulic fracturing that could restrict its use in certain circumstances or make it more costly to utilize. Such measures may address any risk to drinking water, the potential for hydrocarbon migration and disclosure of the chemicals used in fracturing. For example, several states have implemented rules requiring hydraulic fracturing operators to sample ground and surface waters near proposed well sites before operations can begin, and to sample the same sites again after fracturing operations are complete. A majority of states around the country, including Texas, have also adopted some form of fracturing fluid disclosure law to compel disclosure of fracturing fluid ingredients and additives that are not subject to trade secret protection. Other states, such as Ohio and Texas, have begun to study potential seismic risks related to underground injection of fracturing fluids. Any enforcement actions or requirements of additional studies or investigations by governmental authorities where we operate could increase our operating costs and cause delays or interruptions of our operations.

At this time, it is not possible to estimate the potential impact on our business of these state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.

Insurance Matters

As is common in the oil and gas industry, we do not insure fully against all risks associated with our business, either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations or cash flows.

Employees

As of December 31, 2019, we had 79 employees (all employed full-time). None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

As of December 31, 2020, we had 59 employees (all employed full-time). None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory. To date, our pending bankruptcy cases have not materially increased employee attrition.

We also contract for the services of independent consultants involved in land, engineering, regulatory, accounting and other disciplines as needed.

Table of Contents

Available Information

Our website address is www.sundanceenergy.net. We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Nominating and Corporate Governance Committee, Compensation Committee and Reserves Committee, and our Code of Ethics and Business Conduct are available through our website, and we also intend to disclose any amendments to our Code of Ethics, or waivers to such code on behalf of our Chief Executive Officer or Chief Financial Officer, on our website. The contents of our website are not intended to be incorporated by reference into this annual report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. Information is also available on the SEC website at www.sec.gov.

Item 1A. Risk Factors.

We are subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. When considering an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in this report under “Cautionary Statement Regarding Forward-Looking Statements” and other information included and incorporated by reference into this annual report.

We are subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. When considering an investment in our securities, you should carefully consider the risk factors included herein as well as those matters referenced in this report under “Cautionary Statement Regarding Forward-Looking Statements” and other information included and incorporated by reference into this annual report.

Table of Contents

Summary Risk Factors

The following is a summary of the principal risks that could adversely affect our business, operations and financial results, which should be read in conjunction with the more detailed description of each risk factor contained below.

Risks Related to Our Bankruptcy

●

We are subject to risks and uncertainties associated with our Chapter 11 cases and may not be able to obtain confirmation of a Chapter 11 plan of reorganization.

●

Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern. Our financial results may be volatile and may not reflect historical trends.

●

We have substantial liquidity needs and may not be able to obtain sufficient liquidity to confirm a plan of reorganization and exit bankruptcy.

●

Transfers of our equity, or issuances of equity in connection with our Chapter 11 cases, may impair our ability to utilize our federal income tax net operating loss carryforwards and depreciation, depletion and amortization deductions in future years.

●

Our derivative activities will be materially limited upon emergence from bankruptcy and could result in financial losses or could reduce our income.

Risks Related to Our Business

●

The current outbreak of COVID-19 has adversely impacted our business, financial condition, liquidity and results of operations and is likely to have a continuing adverse impact for a significant period of time.

●

Oil, natural gas and NGL prices are volatile, and an extended decline in these prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

●

Increased costs of capital and general economic conditions could adversely affect our business and future growth.

●

Our future revenues are dependent on our ability to successfully replace our proved producing reserves.

●

Development of our estimated proved undeveloped reserves, or PUDs, may take longer than expected and may not be ultimately developed or produced. SEC rules could limit our ability to book additional PUDs.

●

There can be no assurance that we will be able to comply with the terms of our credit facilities.

●

Any significant reduction in our borrowing base under our revolving credit facilities may negatively impact our ability to fund our operations.

●

Our level of indebtedness and restrictions contained in our credit facilities may reduce our financial flexibility.

●

Changes in the differential between benchmark prices of crude oil and natural gas and the reference or regional index price used to price our actual crude oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.

●

Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.

●

We depend upon several significant customers for the sale of most of our crude oil, natural gas and NGL production.

●

We have entered into physical delivery contracts that will require further development in order to deliver all the oil required under such contracts.

●

Our identified drilling locations are subject to many uncertainties that could materially alter the occurrence or timing of their drilling.

●

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.

●

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

●

Our producing properties are located primarily in the Eagle Ford, making us vulnerable to risks associated with operating in limited geographic areas.

Table of Contents

●

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate and any significant inaccuracies in these estimates could materially affect the actual quantities and present value of such reserves.

●

Oil and natural gas price declines may require us to write-down the carrying values of our oil and natural gas properties.

●

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

●

Our inability to market our crude oil and natural gas could adversely affect our business.

●

Competition in the oil and natural gas industry is intense, many of our competitors have resources that are greater than ours and we may not be able to keep pace with technological developments in our industry.

●

The loss of any of our key personnel could adversely affect our business the results of operations, financial condition and future growth.

●

We may incur losses as a result of title deficiencies.

●

Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.

●

Conservation measures and technological advances could reduce demand for crude oil, natural gas and NGLs.

●

Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

●

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs while the physical effects of climate change could disrupt our production and cause us to incur significant costs.

●

Recent federal legislation could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

●

Ineffective internal controls could impact our business and financial results.

●

Our business could be negatively impacted by security threats, including cyber-security threats.

Risks Related to Our Common Stock

The shares of our existing common stock are expected to be canceled in our Chapter 11 proceedings.

Risks Related to Our Bankruptcy

We are subject to risks and uncertainties associated with our Chapter 11 cases.

On March 9, 2021, the Company along with its three subsidiaries, Sundance Energy, Inc., SEA Eagle Ford, LLC, and Armadillo E&P, Inc., filed voluntary petitions seeking relief under Chapter 11 of the United States Bankruptcy Code.

Our operations and ability to develop and execute our business plan, our financial condition, our liquidity and our continuation as a going concern, are subject to the risks and uncertainties associated with our bankruptcy. These risks include the following:

●

our ability to prosecute, confirm and consummate a plan of reorganization with respect to the Chapter 11 cases;

●

the high costs of bankruptcy cases and related fees;

●

our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;

●

our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;

●

our ability to maintain contracts that are critical to our operations;

●

our ability to safely and efficiently re-start operations after a protracted period of minimal activity;

●

our ability to execute competitive contracts with third party contractors while tainted with a bankruptcy legacy;

●

our ability to execute our business plan in the current commodity price environment;

Table of Contents

●

our ability to attract, motivate and retain key employees;

●

the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;

●

our ability to retain our current management team;

●

the ability of third parties to seek and obtain court approval to convert the Chapter 11 cases to a Chapter 7 proceeding; and

●

the actions and decisions of our shareholders, creditors and other third parties who have interests in our Chapter 11 cases that may be inconsistent with our plans.

Delays in our Chapter 11 cases increase the risks of our being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the bankruptcy process.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with our Chapter 11 cases could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, pursuant to the Bankruptcy Code, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. We also need Bankruptcy Court confirmation of the Prepackaged Plan. Because of the risks and uncertainties associated with our Chapter 11 cases, we cannot accurately predict or quantify the ultimate impact of events that occur during our Chapter 11 cases will have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.

We may not be able to obtain confirmation of a Chapter 11 plan of reorganization.

To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a Chapter 11 plan of reorganization, solicit and obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a plan. A confirmation hearing on the Prepackaged Plan has been scheduled to begin on April 19, 2021, but it is possible that hearing could be delayed. It is also possible that the Bankruptcy Court will not confirm the Prepackaged Plan. If the Prepackaged Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern.

Even if the Prepackaged Plan or another Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our oil and gas and increasing expenses. Accordingly, we cannot guarantee that the Plan or any other Chapter 11 plan of reorganization will achieve our stated goals.

Our proposed Prepackaged Plan contemplates that the up to $50 million DIP Facility being provided by the Term Lenders will be converted to equity at emergence. However, if this equitization is not approved by the Bankruptcy Court or otherwise does not occur, and even if our debts are reduced or discharged through the Prepackaged Plan or a different confirmed plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of our Chapter 11 cases. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all. Our ability to continue as a going concern may be dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if a plan is confirmed.

Table of Contents

We have substantial liquidity needs and may not be able to obtain sufficient liquidity to confirm a plan of reorganization and exit bankruptcy.

Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our Chapter 11 cases and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 cases. There are no assurances that our current liquidity is sufficient to allow us to satisfy our obligations related to the Chapter 11 cases, allow us to proceed with the confirmation of a Chapter 11 plan of reorganization and allow us to emerge from bankruptcy. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs or, if sufficient funds are available, offered to us on acceptable terms.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in our Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

We believe it is highly likely that the shares of our existing common stock will be canceled in our Chapter 11 cases and current shareholders will receive no consideration.

The Prepackaged Plan provides, among other things, that upon our emergence from bankruptcy, our existing common stock will be canceled, and the holders of our existing common stock will receive none of our post-emergence common stock. If the Prepackaged Plan is confirmed by the Bankruptcy Court, the existing shareholders receive nothing. Accordingly, any trading in shares of our common stock during the pendency of the Chapter 11 cases is exceptionally risky and highly speculative.

Our financial results may be volatile and may not reflect historical trends.

During the Chapter 11 cases, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments may significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing.

In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We expect to be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

Table of Contents

Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We have net operating loss carryforwards of approximately $406.7 million as of December 31, 2020. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards and amortizable tax basis in our properties may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more stockholders owning 5% or more of a corporation’s common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Following the implementation a plan of reorganization, it is possible that an “ownership change” may be deemed to occur. Under section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation. Further, future deductions for depreciation, depletion and amortization could be limited if the fair value of our assets is determined to be less than the tax basis.

Risks Related to Our Business

The current outbreak of COVID-19 has adversely impacted our business, financial condition and results of operations and is likely to have a continuing adverse impact for a significant period of time.

The COVID-19 pandemic caused a rapid and precipitous drop in demand for oil, which in turn has caused oil prices to plummet since the first week of March 2020, negatively affecting the Company’s cash flow, liquidity and financial position. Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. We cannot predict when oil prices will improve and stabilize.

The current pandemic and uncertainty about its length and depth in future periods has caused the realized oil prices we have received since February 2020 to be significantly reduced, adversely affecting our operating cash flow and liquidity. While we continue to flexibly manage our operations, including capital expenditure levels, based on existing and expected market conditions, our lower levels of cash flow has affected our borrowing capacity and required us to shut-in production that has become uneconomic. These conditions also increased the difficulty in repaying, refinancing or restructuring our long-term debt.

The global COVID-19 pandemic is rapidly evolving, and the ultimate impact of this pandemic is highly uncertain and subject to change. The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and the duration, timing and severity of the impact on domestic and global oil demand, all of which are beyond our control. These factors have had a material adverse impact on our business, financial condition and results of operations, and are likely to have a continuing adverse impact for a significant period of time.

The COVID-19 pandemic and the responses of governmental authorities and companies across the world has caused a rapid and precipitous drop in the demand for oil, which in turn has caused oil prices to plummet since the first week of March 2020. While certain containment measures have been relaxed, the remaining risks and uncertainty surrounding resurgence and reinstitution of more severe containment measures continue to reduce demand for oil and natural gas. The duration and severity of the impact of COVID-19 on the oil and gas industry, including the reduced demand for oil and natural gas and its resulting impact on commodity prices, may continue until a vaccine or alternative treatment is made widely available across the globe. We are unable to predict when, and if, an effective vaccine or alternative treatment for COVID-19 will become available globally.

Table of Contents

Additionally, in March 2020, OPEC and non-OPEC producers failed to agree to production cuts, resulting in a significant drop in crude oil prices. Saudi Arabia also reduced its export prices to certain markets, while increasing its prices in others. In April 2020, members of OPEC and certain non-OPEC producers agreed to production cuts through first quarter 2022. While these production cuts are expected to reduce excess global crude oil inventories in 2021, they are unlikely to be sufficient to offset the sharp demand decreases caused by COVID-19 in the near-term.

Substantially all of our oil production is sold to purchasers under contracts at market-based prices. The current pandemic and uncertainty about its length and depth in future periods has caused the realized oil prices we have received since February 2020 to be significantly reduced, adversely affecting our operating cash flow and liquidity. While we continue to flexibly manage our operations, including capital expenditure levels, based on existing and expected market conditions, our lower levels of cash flow has affected our borrowing capacity and required us to shut-in production that has become uneconomic. These conditions also increased the difficulty in repaying, refinancing or restructuring our long-term debt.

Oil, natural gas and NGL prices are volatile. A substantial or extended decline in the price of these commodities may adversely affect our business, results of operations or financial condition and our ability to meet our capital expenditure obligations and financial commitments.

~~Our~~ revenues, profitability, liquidity, ability to access capital and future growth prospects are highly dependent on the prices we receive for our oil, natural gas and NGLs. The prices of these commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. For example, average daily prices for NYMEX-WTI crude oil ranged from a high of $66.24 per barrel to a low of $46.31 per barrel during 2019. In March 2020, oil prices dropped sharply to under $20 per barrel, and in April 2020, oil prices dropped further and, for a short period of time, were negative. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include:

·Our ~~general~~revenues, ~~worldwide~~profitability, liquidity, ability to access capital and ~~regional~~future ~~economic~~growth prospects are highly dependent on the prices we receive for our oil, natural gas and ~~political~~NGLs. ~~conditions;~~The prices of these commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. For example, in 2020 average daily prices for NYMEX-WTI crude oil ranged from a high of $63.27 per barrel to a low below zero for a short time in April 2020. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control.

~~· the domestic and global supply of, and demand for, oil, natural gas and NGLs;~~

·These ~~the~~factors ~~actions~~include: ~~of OPEC and the ability of OPEC and other producing nations, including Russia, to agree to and maintain production levels;~~

·● ~~the~~general ~~cost~~worldwide ~~of exploring for, developing, producing~~ and ~~marketing~~regional ~~oil,~~economic ~~natural gas~~ and ~~NGLs~~political conditions;

·● the ~~proximity,~~domestic ~~capacity,~~and ~~cost~~global supply of, and ~~availability~~demand offor, oil, natural gas and ~~NGL pipelines and other transportation facilities~~NGLs;

·● the ~~price~~actions ~~and~~of ~~quantity~~OPEC ofand ~~imports~~the ability of ~~foreign~~OPEC and ~~exports~~other ofproducing ~~domestic~~nations, ~~oil~~including Russia, ~~natural~~to ~~gas~~agree to and ~~NGLs~~maintain production levels;

·● the ~~level~~cost of ~~global~~exploring ~~oil~~for, ~~natural~~developing, ~~gas~~producing and ~~NGL~~marketing ~~exploration~~oil, natural gas and ~~production~~NGLs;

·● the ~~level~~proximity, ofcapacity, ~~global~~cost and availability of oil, natural gas and NGL ~~inventories~~pipelines and other transportation facilities;

·● ~~future~~the ~~regulations~~price ~~prohibiting~~and orquantity ~~restricting~~of ~~our~~imports ~~ability~~of toforeign ~~apply~~and ~~hydraulic~~exports ~~fracturing~~of todomestic ~~our~~oil, ~~wells~~natural gas and NGLs;

·● ~~weather~~the ~~conditions~~level ~~and~~of global oil, natural ~~disasters~~gas and NGL exploration and production;

·● ~~global or national health concerns, including~~ the ~~outbreak~~level of ~~pandemic~~global ~~or contagious disease, such as COVID-19, which may reduce the demand for~~ oil, natural gas and NGL ~~because of reduced global or national economic activity~~inventories;

·● ~~domestic~~future ~~and~~regulations ~~foreign~~prohibiting ~~governmental~~or ~~laws,~~restricting ~~regulations~~our ~~and~~ability ~~taxes~~to apply hydraulic fracturing to our wells;

·● ~~volatile~~weather ~~trading~~conditions ~~patterns~~and innatural ~~commodities futures markets~~disasters;

● global or national health concerns, including the outbreak of pandemic or contagious disease, such as COVID-19 , which may reduce the demand for oil, gas and NGL because of reduced global or national economic activity;

●

domestic and foreign governmental laws, regulations and taxes;

●

volatile trading patterns in commodities futures markets;

●

price and availability of competitors’ supplies of oil, natural gas and NGLs;

●

shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas and related infrastructure;

●

technological advances affecting energy consumption; and

●

the price and availability of alternative fuels.

Table of Contents

·Further, ~~price~~oil, natural gas and ~~availability~~NGL prices do not necessarily fluctuate in direct relationship to each other. Because approximately 64% and 18% of ~~competitors’~~our ~~supplies~~estimated proved reserves as of ~~oil~~December 31, ~~natural~~2020 ~~gas~~were attributed to oil and NGLs;, respectively, our financial results are more sensitive to movements in oil prices. The price of oil has been extremely volatile, and we expect this volatility to continue for the foreseeable future. Substantially all of our oil production is sold to purchasers under contracts at market-based prices.

~~· shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas and related infrastructure;~~

·Any ~~technological~~prolonged ~~advances~~substantial decline ~~affecting~~in ~~energy~~the ~~consumption;~~price of oil and natural gas will likely have a material adverse effect on our financial condition and results of operations. We may use various derivative instruments in connection with anticipated oil, natural gas and NGL sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility. As of the date of this report, we have oil derivatives in place covering an average of 3,142 Bbls per day for remainder of 2021. To the extent we are unhedged, we have significant exposure to adverse changes in the prices of oil, natural gas and NGLs that could materially and adversely affect our business and results of operations.

~~· the price and availability of alternative fuels.~~

Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relationship to each other. Because approximately 62% and 18% of our estimated proved reserves as of December 31, 2019 were attributed to oil and NGLs, respectively, our financial results are more sensitive to movements in oil prices. The price of oil has been extremely volatile, and we expect this volatility to continue for the foreseeable future. Substantially all of our oil production is sold to purchasers under contracts at market-based prices.

Any prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition and results of operations. We may use various derivative instruments in connection with anticipated oil, natural gas and NGL sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility. We currently have oil derivatives in place covering the expected 2020 production from our proved developed producing reserves as of January 1, 2020. To the extent we are unhedged, we have significant exposure to adverse changes in the prices of oil, natural gas and NGLs that could materially and adversely affect our business and results of operations.

In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. We might also elect during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, we could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, we may abandon any well if we reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.

There can be no assurance that we will be able to comply with the terms of our credit facilities.

Our credit facilities require us to maintain compliance with certain financial and other covenants. Our ability to comply with these covenants is uncertain and will be affected by our results of operations and financial condition, and events or circumstances beyond our control, including sustained low commodity prices. Absent a waiver or amendment, a breach of any of these covenants contained in our credit facilities could result in an event of default under these facilities.

Specifically, due to the recent sharp decline in commodity prices and expectations for commodity prices in 2020, there is uncertainty as to our ability to remain in compliance with certain of the financial covenants and ratios throughout 2020 and early 2021. If we violate these financial covenants and ratios, or any other covenant in our credit facilities, our indebtedness may become immediately due and payable, the interest rates under our credit facilities may increase and the lenders’ commitment, if any, to make further loans to us may terminate. In the event that some or all of the amounts outstanding under our credit facilities are accelerated and become immediately due and payable, we may not have the funds to repay, or the ability to refinance, such outstanding amounts and our lenders could foreclose upon critical assets. Any of these outcomes would have an adverse effect on our business and financial condition.

20 Specifically, due to the sharp decline in commodity prices and expectations for commodity prices in the first quarter of 2020, beginning in the third quarter of 2020, we were not in compliance with certain of the financial covenants and ratios. Violation of these financial covenants and ratios, caused our indebtedness to become immediately due and payable, the interest rates under our credit facilities increased and the lenders’ commitment to make further loans to us was terminated. We did not have the funds to repay, or the ability to refinance, such outstanding amounts and we filed voluntary petitions seeking relief under Chapter 11 of the United States Bankruptcy Code with support of our lenders under the RSA. The DIP Facility requires that we comply with general affirmative and negative covenants such as prohibiting us from incurring or permitting debt, investments, liens or dispositions unless specifically permitted. Our ability to comply with these provisions may be affected by events beyond our control and our failure to comply or obtain a waiver in the event we cannot comply with a covenant could result in an event of default under the DIP Facility and permit the lenders thereunder to accelerate the loans and otherwise exercise remedies allowable by the agreements governing the DIP Facility. After we emerge from bankruptcy, while we expect to discharge a significant portion of our indebtedness, we expect to have the Exit RBL Facility and Exit Second Out Term Loan Facility (the “Exit Facilities”) that requires compliance with financial covenants and ratios the failure of which could cause the amounts outstanding to immediately become due and payable, the interest rates under the credit facility to increase and the lenders’ commitment to make further loans to be terminated. Any of these outcomes would have an adverse effect on our business and financial condition.

For more information on the covenants under our pre-Chapter 11 credit facilities and the impact of the explanatory paragraph in the audit report, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Credit Facilities”.

Table of Contents

In addition, our credit facilities contain reporting covenants that requires delivery of audited consolidated financial statements and related reports and certificates on or before certain deadlines provided for in our credit facilities. Additionally, our financial statements must be delivered without a going concern or like qualification or exception. Failure to comply with these covenants would constitute a default under our credit facilities. On May 8, 2020 and May 11, 2020, we entered into waivers with our lenders to waive any potential default arising from the failure to deliver audited consolidated financial statements and related reports and certificates by the applicable deadlines, and with respect to inclusion of the going concern explanatory paragraph included in our audit report for the fiscal year ended December 31, 2019. These waivers were effective April 29, 2020, subject to the conditions set forth in the waivers, which included delivery of our audited consolidated financial statements for the fiscal year ended December 31, 2019 and related reports and certificates, and payment of the fees and expenses of the administrative agent incurred in connection with such waivers. In consideration for the waiver under our senior secured revolving credit facility (“Revolving Facility”), we agreed to certain limitations on our ability to effect draws under the Revolving Facility until such time as the second quarter 2020 borrowing base redetermination has been completed. In addition, in consideration for waiver with respect to our second lien term loan facility (“Term Loan”), we agreed to amend certain covenants in the Term Loan, as to be mutually agreed with the Term Loan lenders, within 15 days from the execution date. The waiver under our Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion. Failure to enter into such amendment with respect to our Term Loan within 15 days (or a similar amendment with respect to our Revolving Facility on the date the Term Loan is amended) would constitute an event of default under our credit facilities, in which case the amounts outstanding under our credit facilities could be accelerated and become immediately due and payable. If this occurs, we may not have the funds to repay or ability to refinance such outstanding amounts and our lenders could foreclose upon critical assets. Although we have entered into these waivers, there is no guarantee that our lenders will agree to waive events of default or potential events of default in the future. Failure to obtain such waivers in the future would have an adverse effect on our business and financial condition. For more information on the covenants under our credit facilities and the potential impact of the explanatory paragraph in the audit report, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Credit Facilities”.

Our future revenues are dependent on our ability to successfully replace our proved producing reserves.

Our business strategy is to generate profit through the acquisition, exploration, development and production of oil and natural gas reserves. Proved reserves generally decline as they are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves or both. We may not be able to find, develop or acquire additional reserves on an economically viable basis. Furthermore, if oil and natural gas prices increase, the cost of finding, developing or acquiring additional reserves could also increase.

Development and exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could materially and adversely affect our business, results of operations or financial condition. In addition, the future cost and timing of drilling, completing and operating wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

·● lack of prospective acreage available on acceptable terms;

·● unexpected or adverse drilling conditions;

·● elevated pressure or irregularities in geologic formations;

·● equipment failures or accidents;

·● adverse weather conditions;

·● title problems;

·● limited availability of financing upon acceptable terms;

·● reductions in oil, natural gas and NGL prices;

·● compliance with governmental requirements; and

·● shortages or delays in the availability of drilling rigs, equipment and personnel.

Table of Contents

Even if our exploration, development and drilling efforts are successful, our wells, once completed, may not produce reserves of oil, natural gas or NGLs that are economically viable or that meet our prior estimates of economically recoverable reserves. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial position by reducing our available cash and liquidity. In addition, the potential for production decline rates for our wells could be greater than we expect. Because of the risks and uncertainties inherent to our businesses, our future drilling results may not be comparable to our historical results described elsewhere in this annual report.

Development of our PUDs may take longer than expected and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

As of December 31, 2019, approximately 76% of our total proved reserves were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves. Based on our December 31, 2019 reserve report, it will require an estimated $1.2 billion of capital to develop approximately 76.5 MMBoe of our estimated proved undeveloped reserves over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our proved undeveloped reserves to unproved reserves.

As of December 31, 2020, approximately 57% of our total proved reserves were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves. Based on our December 31, 2020 reserve report, it will require an estimated $288.2 million of capital to develop approximately 26.1 MMBoe of our estimated proved undeveloped reserves over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our proved undeveloped reserves to unproved reserves.

Further, our reserve estimates assume that we can and will make these expenditures and that these operations will be conducted successfully. However, these assumptions may not prove correct. If our plans change and we choose not to spend the capital (or are unable to generate adequate cash flow or obtain the necessary capital under our credit facilities or from other sources) to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to remove these reserves from future reserve estimates. Any such removal of our existing reserves could reduce our ability to borrow and adversely affect our liquidity and available capital.

Our development and exploration projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves with resulting adverse effects on our cash flow and liquidity.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil, natural gas and NGL reserves. We expect our 2020 capital program to be in the range of $40 - $45 million. However, we plan to respond flexibly to market conditions to protect our balance sheet and retain liquidity. 29

The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, regulatory, and technological and competitive developments. We intend to finance our development plan in 2020 primarily with cash flows from operations, but we may also finance our future capital expenditures through a variety of other sources, including available borrowings under our Revolving Facility, through additional asset sales, or through the issuance of debt and/or equity, which may alter or increase our capitalization substantially.

Our cash flows from operations and access to capital are subject to a number of variables, including:

· our proved reserves;

· the volume of oil, natural gas and NGLs we are able to produce and sell from existing proved developed wells;

· the prices at which our oil, natural gas and NGLs are sold;

· the cost at which our oil, natural gas and NGLs are extracted;

· global credit and securities markets;

· our ability to acquire, locate and produce new reserves and the cost of such reserves; and

· the ability of our lenders to provide us with credit or additional borrowing capacity.

Table of Contents

IfAny ~~our~~significant ~~revenues~~reduction orin ~~the~~our ~~amounts~~borrowing webase ~~can borrow~~ under ~~available~~the ~~credit~~Exit ~~facilities~~Facilities ~~decrease~~ as a result of ~~lower~~the ~~oil,~~periodic ~~natural~~borrowing ~~gas~~base orredeterminations ~~NGL prices, operating difficulties, declines in reserves~~ or ~~for~~otherwise ~~any other reason, we~~ may ~~have~~negatively ~~limited~~impact ~~ability to obtain the capital necessary to sustain~~ our ~~operations~~ability ~~at current levels. If additional capital is needed, we may not be able~~ to ~~obtain~~fund ~~debt or equity financing on terms acceptable to us, or at all. If cash generated by operations or cash available under~~ our ~~credit facilities is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our~~ operations relating to development of our locations, which in turn could lead to a decline in our oil, natural gas and NGL reserves and production levels, and could materially and adversely affect our business, results of operations and financial condition.

Any significant reduction in our borrowing base under our Revolving Facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

~~Our~~On ~~Revolving~~the ~~Facility~~effective ~~generally~~date ~~limits~~of the ~~amounts~~Prepackaged wePlan, ~~can~~our ~~borrow~~existing upRevolving toFacility awill ~~borrowing~~be ~~base amount~~extinguished, ~~which~~and ~~the~~we ~~lenders,~~will inenter ~~their~~into ~~sole~~the ~~discretion~~Exit Facilities, ~~determine~~including ~~semiannually~~a onnew ~~May~~reserve-based 1lending ~~and~~revolving ~~November~~credit 1facility ofhaving ~~each year. Our Revolving Facility has~~ a borrowing base of $~~210~~107.05 million (~~$190~~inclusive ~~million elected commitment),~~ of ~~which~~a $~~115~~20.0 million ~~was~~letter ~~outstanding as~~ of ~~December~~credit ~~31, 2019~~subfacility). ~~Our~~The ~~next~~ borrowing base ~~redetermination~~will isbe ~~the~~redetermined ~~second~~on ~~quarter of 2020. Redeterminations are based upon~~ a ~~number~~semi-annual ofbasis ~~factors, including commodity prices~~ and ~~reserve~~the ~~levels.~~next Inscheduled ~~addition,~~redetermination ~~our~~is ~~lenders~~anticipated ~~have substantial flexibility~~ to ~~reduce~~occur ~~our~~on ~~borrowing~~or ~~base~~about ~~due~~March to1, ~~subjective factors. Upon a redetermination~~2022, wesubject ~~could be required~~ to ~~repay~~any ainterim ~~portion~~unscheduled ofredeterminations ~~the~~as ~~debt~~described owed under our Revolving Facility to the extent our outstanding borrowings at such time exceeds the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in ~~a default under~~ the ~~terms~~Exit ~~of our Revolving Facility and an acceleration of the loans outstanding under our Revolving Facility and our other credit facilities~~Facilities. Failure to timely pay these debt obligations when due could cause us to lose our assets through mortgage foreclosure, which would materially and adversely affect our business, results of operations and financial condition.

Additionally, in the future we may not have access to adequate funding under our Revolving Facility as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of our lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover any defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans or make required repayments under the Revolving Facility or our other credit facilities, which would materially and adversely affect our business, results of operations and financial condition.

~~Effective~~Redeterminations ~~April~~are ~~29,~~based ~~2020,~~upon wea ~~entered~~number ~~into~~of afactors, ~~waiver~~including ~~with~~commodity ~~respect~~prices toand ~~any~~reserve ~~potential~~levels. ~~default~~In ~~arising~~addition, ~~from~~our ~~the~~lenders ~~reporting~~have ~~covenant~~substantial ~~under~~flexibility to reduce our ~~Revolving~~borrowing ~~Facility~~base ~~that~~due ~~requires~~to ~~delivery~~subjective offactors. ~~audited~~Upon ~~consolidated~~a ~~financial~~redetermination, ~~statements~~we oncould orbe ~~before~~required ~~the~~to ~~deadline~~repay ~~provided~~a ~~for~~portion inof the ~~Revolving~~debt ~~Facility,~~owed ~~and~~under toour ~~deliver~~revolving ~~such~~credit ~~financial~~facilities ~~statements~~to ~~without~~the aextent ~~going~~our ~~concern~~outstanding orborrowings ~~like~~at ~~qualification~~such ortime ~~exception~~exceeds ~~for~~ the ~~year~~redetermined ~~ended~~borrowing ~~December 31, 2019~~base. In ~~consideration~~We ~~for~~may ~~the~~not ~~waiver,~~have wesufficient ~~agreed~~funds to ~~certain~~make ~~limitations~~such onrepayments, ~~our~~which ~~ability~~could toresult ~~effect~~in ~~draws~~a default under the ~~Revolving~~terms ~~Facility~~of ~~until~~our ~~such~~revolving ~~time~~credit asfacilities ~~the~~and ~~second~~an ~~quarter~~acceleration ~~2020~~of ~~borrowing~~the ~~base~~loans ~~redetermination~~outstanding ~~has~~under ~~been~~any ~~completed~~of our credit facilities. ~~See~~ ~~Part~~Failure ~~II,~~to ~~Item~~timely 7.pay ~~“Management’s~~these ~~Discussion~~debt ~~and~~obligations ~~Analysis~~when ofdue ~~Financial~~could ~~Condition~~cause us to lose our assets through mortgage foreclosure, which would materially and ~~Results~~adversely affect our business, results of ~~Operations”~~operations ~~under~~and ~~“Credit~~financial ~~Facilities”~~condition.

~~The current outbreak of COVID-19 has adversely impacted our business, financial condition and results of operations and is likely to have a continuing adverse impact for a significant period of time.~~

~~The~~In ~~COVID-19~~the ~~pandemic~~future, ~~has~~we ~~caused~~may anot ~~rapid~~be ~~and~~able ~~precipitous~~to ~~drop~~access inadequate ~~demand~~funding ~~for~~under ~~oil,~~our ~~which~~revolving incredit ~~turn~~facilities ~~has~~as ~~caused~~a ~~oil~~result ~~prices~~of toa ~~plummet~~decrease ~~since~~in ~~the~~our ~~first~~borrowing ~~week~~base ofdue ~~March~~to ~~2020,~~the ~~negatively~~outcome ~~affecting~~of ~~the~~a ~~Company’s~~subsequent ~~cash~~borrowing ~~flow,~~base ~~liquidity~~redetermination ~~and~~or ~~financial~~an ~~position. Moreover,~~unwillingness ~~the~~or ~~uncertainty~~inability ~~about~~on the ~~duration~~part of ~~the~~our ~~COVID-19~~lending ~~pandemic~~counterparties ~~has~~to ~~caused~~meet ~~storage~~their ~~constraints~~funding inobligations and the ~~United~~inability ~~States~~of ~~resulting~~other ~~from~~lenders ~~over-supply~~to ofprovide ~~produced~~additional ~~oil,~~funding ~~which~~to iscover ~~expected~~any todefaulting ~~significantly~~lender’s ~~decrease~~portion. ~~our~~Declines ~~realized~~in ~~oil~~commodity prices could result in a determination to lower the ~~second~~borrowing ~~quarter~~base ofin ~~2020~~the future and, ~~potentially~~in ~~beyond.~~such ~~Oil~~a ~~prices~~case, ~~are~~we ~~expected~~could tobe ~~continue~~required to berepay ~~volatile~~any asindebtedness ain ~~result~~excess of ~~these~~the ~~events~~redetermined ~~and~~borrowing ~~the~~base. ~~ongoing~~As ~~COVID-19~~a ~~outbreak~~result, ~~and~~we asmay ~~changes~~be inunable ~~oil~~to ~~inventories,~~implement ~~oil~~our ~~demand~~drilling and ~~economic~~development ~~performance~~plan, ~~are~~make ~~reported.~~acquisitions Weor ~~cannot~~otherwise ~~predict~~carry ~~when~~out ~~oil~~business ~~prices~~plans ~~will~~or ~~improve~~make required repayments under our credit facilities, which would materially and ~~stabilize~~adversely affect our business, results of operations and financial condition.

~~Table~~In addition, the availability of ~~Contents~~ borrowings under the Exit Facilities is subject to various financial and non-financial covenants and restrictions. As a result of these covenants, we may be unable to finance future operations or capital needs.

The current pandemic and uncertainty about its length and depth in future periods has caused the realized oil prices we have received since February 2020 to be significantly reduced, adversely affecting our operating cash flow and liquidity. While we continue to flexibly manage our operations, including capital expenditure levels, based on existing and expected market conditions, our lower levels of cash flow could affect our borrowing capacity and may require us to shut-in production that has become uneconomic. These conditions may also increase the difficulty in repaying, refinancing or restructuring our long-term debt.

~~The~~See ~~COVID-19~~Part ~~pandemic is rapidly evolving~~II, ~~and~~Item ~~the ultimate impact of this pandemic is highly uncertain and subject to change~~7. ~~The~~“Management’s ~~extent~~Discussion ~~of the impact of the COVID-19 pandemic on our operational~~ and ~~financial~~Analysis ~~performance will depend on future developments, including the duration and spread~~ of ~~the~~Financial ~~pandemic,~~Condition ~~its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel,~~ and ~~the~~Results ~~duration, timing and severity~~ of ~~the~~Operations” ~~impact~~under on“Credit ~~domestic and global oil demand~~Facilities”.

Changes in the differential between benchmark prices of oil and natural gas and the reference or regional index price used to price our actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.

The reference or regional index prices that we will use to price our oil and natural gas sales sometimes will reflect a discount to the relevant benchmark prices. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict oil and natural gas differentials. Changes in differentials between the benchmark price for oil and natural gas and the reference or regional index price we reference in our sales contracts could materially and adversely affect our business, results of operations and financial condition.

~~Our level of indebtedness may reduce our financial flexibility.~~ 30

· a portion of our cash flow from operations would be used to pay interest on borrowings;

· the covenants contained in available credit facilities limit our ability to borrow additional funds, pay dividends, dispose of assets or issue shares of preferred stock and otherwise may affect our flexibility in planning for, and reacting to, changes in general business and economic conditions;

· a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes;

· a leveraged financial position would make us more vulnerable to economic downturns and decreases in commodity prices and could limit our ability to withstand competitive pressures; and

· the debt we currently hold, as well as any debt that we incur under our existing Revolving Facility will be at variable rates which could make us vulnerable to an increase in interest rates.

Table of Contents

Our level of indebtedness and restrictions contained in our debt agreements may reduce our financial flexibility.

We intend to fund our capital expenditures primarily through cash flow from operations and, if necessary borrowings under available credit facilities and alternative debt or equity financings. If we obtain alternative debt or equity financing for these or other purposes, the related risks that we now face could intensify. The Exit Facilities that we expect to be in effect upon effectiveness of the Prepackaged Plan will contain, and any other existing or future indebtedness of ours would likely contain, a number of covenants that impose operating and financial restrictions on us. Our level of debt and debt agreements could materially and adversely affect our business, results of operations and financial condition in several important ways, including the following:

●

a portion of our cash flow from operations would be used to pay interest on borrowings;

●

the covenants contained in available credit facilities may restrict our ability to incur additional debt, guarantee indebtedness or create liens on certain assets, pay dividends on or make distributions in respect of, or repurchase or redeem, our capital stock or make other restricted payments, dispose of assets or issue shares of preferred stock, prepay, redeem or repurchase certain debt, make loans or certain investments and otherwise may affect our flexibility in planning for, and reacting to, changes in general business and economic conditions;

●

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes;

●

a leveraged financial position would make us more vulnerable to economic downturns and decreases in commodity prices and could limit our ability to withstand competitive pressures; and

●

the debt we currently hold, as well as any debt that we incur under our available credit facilities will be at variable rates which could make us vulnerable to an increase in interest rates.

The interest rates under our credit facilities may be impacted by the phase-out of LIBOR.

The London Interbank Offered Rate (“LIBOR”) is the basic rate of interest used in lending between banks on the London interbank market and is widely used as a reference for setting the interest rates on loans globally. We generally use LIBOR as a reference rate to calculate interest rates under our credit facilities. In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. It is unclear if LIBOR will cease to exist at that time or if new methods of calculating LIBOR will be established such that it continues to exist after 2021. If LIBOR ceases to exist or replaced with an alternative reference rate, we may need to renegotiate our credit agreements to replace LIBOR with an agreed upon replacement index, and certain of the interest rates under our credit agreements may change. The new rates may not be as favorable to us as those in effect prior to any LIBOR phase-out. We may also find it desirable to engage in more frequent interest rate hedging transactions.

Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.

The oil and natural gas business involves operating hazards such as:

·● well blowouts;

·● mechanical failures;

·● fires and explosions;

·● pipe or cement failures and casing collapses, which could release natural gas, oil, drilling fluids or hydraulic fracturing fluids;

·● uncontrollable flows of oil, natural gas or well fluids;

·● geologic formations with abnormal pressures;

·● handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;

·● pipeline ruptures or spills;

·● inclement weather, including flooding, hurricanes or other severe weather events;

·● releases of toxic gases; and

·● other environmental hazards and risks (including groundwater contamination).

Table of Contents

Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims, regulatory investigation, penalties and suspension of operation and other damage to our properties and the property of others.

We maintain insurance against losses and liabilities in accordance with customary industry practices and in amounts that our management believes to be prudent. However, insurance against all operational risks is not available to us. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented.

In addition, losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot insure fully against pollution and environmental risks. We cannot assure investors that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

Table of Contents

We depend upon several significant customers for the sale of most of our oil, natural gas and NGL production.

For the year ended December 31, 2019, purchases by two customers each accounted for over 10% of our total sales revenues. The loss of one or more of these customers or the inability or failure of either of these customers to meet their obligations to us or their insolvency or liquidation could adversely affect our revenues in the short term. While we believe that we can procure substitute or additional customers to offset the loss of one or more of our current customers, there is no assurance that we would be successful in doing so on terms acceptable to us or at all. The availability of a ready market for any oil, natural gas or NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil, natural gas and NGL production and federal regulation of oil, natural gas and NGL in interstate commerce.

For the year ended December 31, 2020, purchases by two customers each accounted for over 10% of our total sales revenues. The loss of one or more of these customers or the inability or failure of either of these customers to meet their obligations to us or their insolvency or liquidation could adversely affect our revenues in the short term. While we believe that we can procure substitute or additional customers to offset the loss of one or more of our current customers, there is no assurance that we would be successful in doing so on terms acceptable to us or at all. The availability of a ready market for any oil, natural gas or NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil, natural gas and NGL production and federal regulation of oil, natural gas and NGL in interstate commerce.

SEC rules could limit our ability to book additional PUDs in the future.

~~SEC~~ rules require that, subject to limited exceptions, our PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement limits our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write-down our PUDs if we do not drill those wells within the required five-year time frame, or if oil and natural gas prices decrease, making the PUDs uneconomic. Lower PV‑10 value, resulting from fewer PUDs, may negatively impact our investor perception.

SEC rules require that, subject to limited exceptions, our PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement limits our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write-down our PUDs if we do not drill those wells within the required five-year time frame, or if oil and natural gas prices decrease, making the PUDs uneconomic. Lower PV-10 value, resulting from fewer PUDs, may negatively impact our investor perception.

Our planned drilling involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques, which are subject to risks. As a result, drilling results may not meet our expectations for reserves or production.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to:

·● landing our well bore in the desired formation;

·● staying in the desired formation while drilling horizontally through the formation;

·● running our casing the entire length of the well bore; and

·● being able to run tools and other equipment consistently through the well bore.

Risks that we face while completing our wells include, but are not limited to:

·● being able to fracture stimulate the planned number of stages;

·● being able to run tools the entire length of the well bore during completion operations;

·● successfully cleaning out the well bore after completion of the final fracture stimulation stage; and

·● negatively impacting offset producing wells through subsurface communication during fracture stimulation.

Table of Contents

The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling does not meet our anticipated results or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise and/or oil and natural gas prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

Table of Contents

Our identified drilling locations are scheduled to be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

·● ongoing review and analysis of geologic and engineering data;

·● the availability of sufficient capital resources to us and the other participants for drilling and completing of the locations;

·● the approval of the locations by other participants once additional data has been compiled;

·● economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability and prices of drilling rigs and personnel;

·● the ability to maintain, extend or renew leases and permits on reasonable terms for the locations;

·● additional due diligence;

·● regulatory requirements and restrictions; and

·● the opportunity to divert our drilling budget to preferred locations.

Although we have identified or budgeted for numerous drilling locations, we may not be able to lease or drill those locations within our expected time frame or at all. Wells that are currently part of our capital plan may be based on results of drilling activities in other areas that we believe are geologically similar to a location rather than on analysis of seismic or other data in the location area, in which case actual drilling and results are likely to vary, possibly materially, from results in other areas. In addition, our drilling schedule may vary from our expectations because of future uncertainties, and our ability to produce oil, natural gas and NGLs may be significantly affected by the availability and prices of equipment and personnel.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing properties. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce oil, natural gas or NGLs from these or any other potential locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in the addition of proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

27 33

Table of Contents

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which the oil and gas industry has historically increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, and the costs for those items also increased. We cannot predict the future availability or costs of these items. However, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to maintain or increase our development activities, could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.

~~Certain of our undeveloped leasehold acreage is subject to leases expiring over the next several years unless production is established on units containing the acreage.~~

Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production is established. For these properties, if production in commercial quantities has not been established on the leased property or units that include the leased property containing these leases, our leases will expire and we will lose our right to develop the related properties. As of December 31, 2019, 2,118 net acres of our total acreage position were not held by production. For the acreage underlying such properties, if production in paying quantities is not established on units containing these leases, or extensions are not successfully obtained, 1,927 net acres will expire in 2020, and approximately 191 net acres will expire in 2021 and 2022. In addition, approximately 4,500 net acres is currently held by production, but is subject to future drilling obligations.

We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

In accordance with our business strategies, we periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

·● recoverable reserves;

·● future oil and natural gas prices and their appropriate differentials;

·● timing of development;

·● development and operating costs; and

·● potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Table of Contents

Significant acquisitions and other strategic transactions may involve other risks, including:

·● diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

·● the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;

·● difficulty associated with coordinating geographically separate organizations; and

·● the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

Table of Contents

In addition, even if we successfully integrate an acquisition, it may not be possible to realize the full benefits we may expect, including with respect to estimated proved reserves, production volume or cost savings from operating synergies, within our expected time frame. Anticipated benefits of an acquisition may also be offset by operating losses relating to changes in commodity prices in oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. Failure to realize the benefits we anticipate from an acquisition may materially and adversely affect our business, results of operations and financial condition.

Our producing properties are located primarily in the Eagle Ford, making us vulnerable to risks associated with operating in a limited number of geographic areas.

All of our producing properties are geographically concentrated in the Eagle Ford area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by governmental regulation (including any proration and production restrictions in light of the COVID-19 pandemic or otherwise), processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs, any of which could materially and adversely affect our business, results of operations and financial condition.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate and any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves.

The reserve data in this annual report represent only estimates. There are uncertainties inherent in estimating oil and natural gas reserves and their estimated value, including many factors beyond our control. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and is based on assumptions that may vary considerably from actual results. Reservoir engineering also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Accordingly, actual production, oil and natural gas prices, revenue, taxes, operating expenses, expenditures and quantities of recoverable oil and natural gas reserves will likely vary, possibly materially, from estimates. Any significant variance in our estimates or the accuracy of our assumptions could materially affect the estimated quantities and present value of reserves shown in this annual report, which could materially and adversely affect our business, results of operations and financial condition.

~~Table~~Our ofderivative ~~Contents~~ activities will be materially limited upon emergence from bankruptcy and could result in financial losses or could reduce our income.

~~Our derivative activities could result in financial losses or could reduce our income.~~

Because oil and natural gas prices are subject to volatility, we ~~regularly~~have ~~enter~~historically entered into price-risk-management transactions such as fixed-rate swaps, costless collars, puts, calls and basis differential swaps to reduce our exposure to price declines associated with a portion of our oil and natural gas production and thereby achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of oil and natural gas. Our derivative arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in oil and natural gas prices. Following our emergence from bankruptcy, our derivative activities will be materially governed by loan agreements and we may be unable to sufficiently mitigate implication of price or production changes.

These arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of oil and natural gas or a sudden, unexpected event that materially impacts oil or natural gas prices. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.

~~If the recent decline in oil and natural gas prices is sustained or prices decline further, we may be required to write-down the carrying values of our oil and natural gas properties.~~ 35

~~Accounting~~Table ~~rules require that we periodically review the carrying value~~ of our producing oil and gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews (which may include depressed oil, natural gas and NGL prices and the continuing evaluation of development plans, production data, economics, possible asset sales and other factors), we may be required to write-down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. For example, we incurred impairment of oil and gas properties held for sale of $10.0 million and $43.0 million during 2019 and 2018, respectively. Contents

Oil and natural gas price declines may require us to write-down the carrying values of our oil and natural gas properties.

Accounting rules require that we periodically review the carrying value of our producing oil and gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews (which may include depressed oil, natural gas and NGL prices and the continuing evaluation of development plans, production data, economics, possible asset sales and other factors), we may be required to write-down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. For example, we incurred impairment of proved oil and gas properties of $331.9 million during 2020 and impairment of oil and gas properties held for sale of $10.0 million during 2019.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

The discounted future net cash flows in this annual report are not necessarily the same as the current market value of our estimated oil and natural gas reserves. In accordance with SEC regulations, the estimated discounted future net cash flows from proved reserves are based on the average of the historical sales price on the first day of each month in the applicable year, with costs determined as of the date of the estimate. Actual future net cash flows also will be affected by various factors, including:

·● the actual prices we receive for oil and natural gas;

·● our actual operating costs in producing oil and natural gas;

·● the amount and timing of actual production;

·● supply and demand for oil and natural gas;

·● increases or decreases in consumption of oil and natural gas; and

·● changes in governmental regulations or taxation.

In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

Our inability to market our oil and natural gas could adversely affect our business.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and gathering facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on favorable terms could materially and adversely affect our business, results of operations and financial condition.

Table of Contents

Our productive properties may be located in areas with limited or no access to pipelines, thereby requiring compression facilities or delivery by other means, such as trucking and train. Such restrictions on our ability to sell our oil or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we are unable to market and sustain production from a particular lease for an extended period of time, possibly resulting in the loss of a lease due to the lack of commercially established production.

Table of Contents

We generally deliver our oil and natural gas production through gathering systems and pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our oil and natural gas production may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system or for other reasons as dictated by the particular agreements. We may also enter into firm transportation arrangements for additional production in the future. Because we are obligated to pay fees on minimum volumes to our service providers under these agreements regardless of actual volume throughput, these firm transportation agreements may be significantly more costly than interruptible or short-term transportation agreements, which could adversely affect our business and results of operations.

A portion of our oil and natural gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of adverse weather conditions or natural disasters, accidents, loss of pipeline or gathering system access, or field personnel issues or strikes. We may also voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted or curtailed, it could adversely affect our business and results of operations.

Our credit facilities have substantial restrictions and financial covenants that restrict our business and financing activities.

Our credit facilities contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability, subject to satisfaction of certain conditions, to:

·The ~~incur~~Exit ~~additional~~Facilities ~~indebtedness~~we expect to be in effect upon emergence from the Chapter 11 cases contain a number of restrictive covenants that impose significant operating and ~~guarantee~~financial ~~indebtedness;~~restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability, subject to satisfaction of certain conditions, to, among other things:

~~· pay dividends or make other distributions or repurchase or redeem capital stock;~~

·● ~~enter~~incur ~~into~~additional ~~hedging~~indebtedness ~~agreements covering volumes above specified ceilings~~ or ~~below~~guarantee ~~specified floors~~indebtedness;

·● ~~prepay,~~pay ~~redeem~~dividends or make other distributions or repurchase ~~certain~~or ~~debt~~redeem capital stock;

·● ~~issue~~enter ~~certain~~into ~~preferred~~hedging ~~stock~~agreements covering volumes above specified ceilings or ~~similar~~below ~~equity~~specified ~~securities~~floors;

·● ~~make~~prepay, ~~loans~~redeem ~~and~~or ~~investments~~repurchase certain debt;

·● ~~sell~~issue ~~assets~~certain preferred stock or similar equity securities;

·● ~~incur~~make ~~liens~~loans or certain investments;

·● ~~enter~~sell ~~into~~certain ~~transactions with affiliates~~assets;

·● ~~alter~~create ~~the~~liens ~~businesses~~on wecertain ~~conduct~~assets;

·● enter into ~~agreements~~certain ~~restricting~~transactions ~~our~~with ~~subsidiaries’ ability to pay dividends~~affiliates; ~~and~~

·● ~~consolidate,~~alter ~~amalgamate,~~the ~~merge~~businesses orwe ~~sell all or substantially all of our assets.~~conduct;

As● aenter ~~result,~~into weagreements ~~may~~restricting ~~be limited in how we conduct~~ our ~~business,~~subsidiaries’ unable to raise additional debt or equity financing to operate during general economic or business downturns or unable to compete effectively or to take advantage of new business opportunities. These restrictions may further affect our ability to ~~grow~~pay in accordance with our strategy. In addition, our financial results, our substantial indebtedness and our credit ratings could adversely affect the availability and terms of our current and future financing. dividends;

31 ● consolidate, amalgamate, merge or sell all or substantially all of our assets; and

●

designate our subsidiaries as unrestricted subsidiaries.

In addition, the availability of borrowings under the DIP Facility and Exit Facilities is subject to various financial and non-financial covenants and restrictions. As a result of these covenants, we may be limited in how we conduct our business, unable to raise additional debt or equity financing to operate during general economic or business downturns or unable to compete effectively or to take advantage of new business opportunities. These restrictions may further affect our ability to grow in accordance with our strategy. In addition, our financial results, our substantial indebtedness and our credit ratings could adversely affect the availability and terms of our current and future financing.

Failure to comply with the covenants under these facilities or any of our other indebtedness could result in an event of default, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. In the event of any such default, the lenders thereunder:

●

will not be required to lend any additional amounts to us;

●

could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable and terminate all commitments to extend further credit; or

●

could require us to apply all of our available cash to repay these borrowings.

Table of Contents

Such actions by the lenders could cause cross defaults under our other indebtedness. If we were unable to repay those amounts, the lenders or holders under these facilities and our other secured indebtedness could proceed against the collateral granted to them to secure that indebtedness and we could be forced into bankruptcy or liquidation.

Increased costs of capital could adversely affect our business.

Our business and operating results can be adversely affected by factors such as the availability, terms and cost of capital and increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Disruptions in the global financial markets may lead to an increase in interest rates or a contraction in credit availability, which would impact our ability to finance our operations. We will require continued access to capital for the foreseeable future. A significant reduction in the availability of credit could materially and adversely affect our business, results of operations and financial condition.

Competition in the oil and natural gas industry is intense and many of our competitors have resources that are greater than ours.

The oil and natural gas industry is highly competitive. Public integrated and independent oil and natural gas

companies, private equity backed and private operators are all active bidders for desirable oil and natural gas properties as well as the equipment and personnel required to operate those properties. Many of these companies have substantially greater financial resources, staff and facilities than we do. There is a risk that increased industry competition will adversely impact our ability to purchase assets or secure services at prices that will allow us to generate sufficient returns on investment in the future.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

The loss of any of our key personnel could adversely affect our business the results of operations, financial condition and future growth.

We are reliant on a number of key members of our executive management team. Loss of such personnel may have an adverse effect on our performance. We operate in a highly competitive environment and competition for qualified personnel is intense. We may be unable to hire suitable field personnel for our technical team or there may be periods of time where a particular position remains vacant while a suitable replacement is identified and appointed. Our ability to sustain current operations or manage our growth will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. We may not be successful in attracting and retaining the personnel required to grow or operate our business profitably.

Table of Contents

Our ability to manage growth will have an impact on our business, results of operations and financial condition.

Our growth historically has been achieved through the acquisition of leaseholds and the expansion of our drilling programs. Future growth may place strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and independent contractors, potentially adversely affecting our financial position and results of operations. Our ability to grow will depend on a number of factors, including:

~~· our ability to obtain leases or options on properties;~~

·● our ability to ~~identify~~obtain ~~and~~leases ~~acquire~~or ~~new~~options ~~exploratory~~on ~~prospects~~properties;

·● our ability to ~~develop~~identify ~~existing~~and acquire new exploratory prospects;

·● our ability to ~~continue~~develop toexisting ~~retain and attract skilled personnel~~prospects;

32 ● our ability to continue to retain and attract skilled personnel;

~~Table~~● ofour ~~Contents~~ ability to maintain or enter into new relationships with project partners and independent contractors;

·● ~~our~~the ~~ability~~results toof ~~maintain~~our ordrilling ~~enter into new relationships with project partners and independent contractors~~programs;

·● ~~the~~commodity ~~results of our drilling programs~~prices; and

·● ~~commodity~~our ~~prices;~~access ~~and~~to capital.

~~· our access to capital.~~

We may not be successful in upgrading our technical, operational and administrative resources or increasing our internal resources sufficiently to provide certain of the services currently provided by third parties, and we may not be able to maintain or enter into new relationships with project partners and independent contractors on financially attractive terms, if at all. Our inability to achieve or manage growth may materially and adversely affect our business, results of operations and financial condition.

We may incur losses as a result of title deficiencies.

We may lose title to, or interests in, our leases and other properties if the conditions to which those interests are subject are not satisfied or if insufficient funds are available to meet the commitments.

The existence of title deficiencies with respect to our oil and natural gas properties could reduce their value or render such properties worthless, which would have a material adverse effect on our business and financial results. We do not obtain title insurance and have not necessarily obtained drilling title opinions on all of our oil and natural gas properties. As is customary in the industry in which we operate, we generally rely upon the judgment of oil and natural gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract, and we generally make title investigations and receive title opinions of local counsel before we commence drilling operations. In some cases, we perform curative work to correct deficiencies in the marketability or adequacy of the title assigned to us. In cases involving more serious title problems, the amount paid for affected oil and natural gas leases can be lost, and the target area can become undrillable. While we undertake to cure all title deficiencies prior to drilling, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease, our investment in the well and the right to produce all or a portion of the minerals under the property. A significant portion of our acreage is undeveloped leasehold, which has a greater risk of title defects than developed acreage.

~~Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.~~

Oil and gas operations are subject to various federal, state, local and foreign laws and government regulations that may change from time to time. Matters subject to regulation include discharge permits for drilling operations, well testing, plug and abandonment requirements and bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. Other federal, state, local and foreign laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and gas operations, including drilling fluids and wastewater. Compliance with existing, new or modified laws and regulations could result in substantial costs, delay our operations or otherwise have a material adverse effect on our business, results of operations and financial condition. We may not be able to recover some or any of these costs from insurance. Federal and state regulators are increasingly targeting GHG emissions from oil and gas operations. While these regulatory efforts are evolving, they may require the installation of emission controls or mandate other action that may result in increased costs of operation, delay, uncertainty or exposure to liability. 39

Table of Contents

Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.

Oil and gas operations are subject to various federal, state, local and foreign laws and government regulations that may change from time to time. Matters subject to regulation include discharge permits for drilling operations, well testing, plugging and abandonment requirements and bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. Other federal, state, local and foreign laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and gas operations, including drilling fluids and wastewater. Compliance with existing, new or modified laws and regulations could result in substantial costs, delay our operations or otherwise have a material adverse effect on our business, results of operations and financial condition. We may not be able to recover some or any of these costs from insurance. Federal and state regulators are increasingly targeting GHG emissions from oil and gas operations. While these regulatory efforts are evolving, they may require the installation of emission controls or mandate other action that may result in increased costs of operation, delay, uncertainty or exposure to liability.

There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we may be liable, regardless of whether we were at fault, for the full cost of removing or remediating contamination, even when multiple parties contributed to the release and the contaminants were released in compliance with all applicable laws. In addition, accidental spills or releases on our properties may expose us to significant liabilities that could have a material adverse effect on our financial condition and results of operations. Aside from government agencies, the owners of properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal and other private parties may be able to sue us to enforce compliance with environmental laws and regulations, as well as collect penalties for violations or obtain damages for any related personal injury or property damage. Some sites we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.

In addition, our operations and financial performance may be adversely affected by governmental action, including delay, inaction, policy change or the introduction of new, or amendment of or changes in interpretation of existing legislation or regulations, particularly in relation to foreign ownership, access to infrastructure, environmental regulation (including in respect of carbon emissions and management), royalties and production and exploration licensing. For instance, in January 2021, the Biden administration issued a series of executive orders focused on environmental matters that could impact demand for oil and gas and, in turn, our financial performance. One of the executive orders directed all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions promulgated during the prior administration that may be inconsistent with the administration’s policies. Another of the executive orders was focused on addressing climate change and, among other things, directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The executive order also directed the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. Legal challenges to the suspension have already been filed and are currently pending, so the ultimate effect of such orders is uncertain at this time.

Table of Contents

The conduct of exploration for, and production of, hydrocarbons may expose our staff to potentially harmful working environments. Occupational health and safety legislation and regulations differ in each jurisdiction. In March 2016, the Occupational Safety and Health Administration issued a final rule related to worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. Compliance with the rule may require significant investment in engineering and workplace controls. If any of our employees suffer injury or death, compensation payments or fines may have to be paid, and such circumstances could result in the loss of a license or permit required to carry on the business, or other legislative sanction, all of which have the potential to materially and adversely affect our business, results of operations and financial condition.

We have entered into physical delivery contracts that will require further development in order to deliver all the oil required under such contracts.

We entered into midstream contracts with a large pipeline company and production purchaser to provide gathering, processing, transport and marketing of production for the Eagle Ford assets acquired in 2018. The contracts contain minimum revenue commitments, a portion of which is secured by letters of credit and performance bonds. If the planned development program is not executed to the extent projected, we may not produce sufficient quantities of hydrocarbons to meet the minimum revenue commitments and may be required to make cash deficiency payments. The deficiency payments would reduce liquidity to invest in growing the business and profitability. If we are unable to make the deficiency payments, the letters of credit and performance bonds may be drawn causing an increase in our level of indebtedness and potentially result in a default under our loan covenants.

Hydraulic fracturing, which is the process used for releasing hydrocarbons from shale rock, has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.

Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into deep rock formations to stimulate oil or natural gas production. Currently, hydraulic fracturing is primarily regulated in the U.S. at the state level, which generally focuses on regulation of well design, pressure testing and other operating practices. However, some states and local jurisdictions across the U.S., including states in which we operate, have begun adopting more restrictive regulations, including measures such as:

·● required disclosure of chemicals used during the hydraulic fracturing process;

·● restrictions on wastewater disposal activities;

34 ● required baseline and post-drilling sampling of water supplies in close proximity to hydraulic fracturing operations;

●

new municipal or state land use regulations, such as changes in setback requirements, which may restrict drilling locations or related activities;

●

financial assurance requirements, such as the posting of bonds, to secure site restoration obligations; and

●

local moratoria or even bans on oil and natural gas development utilizing hydraulic fracturing in some communities.

Table of Contents

·In ~~required~~addition, ~~baseline~~the federal government has the authority to regulate hydraulic fracturing on federal and ~~post-drilling~~tribal ~~sampling~~lands. Under the Obama administration, the Bureau of Land Management (“BLM”) issued its final regulations for hydraulic fracturing on federal and tribal lands that require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water ~~supplies~~management inand ~~close~~storage, ~~proximity~~and tomore stringent well integrity measures associated with hydraulic fracturing operations; on public land. At the U.S. federal level, hydraulic fracturing that does not involve the use of diesel fuels is exempt from regulation under the Safe Drinking Water Act (“SDWA”). However, the U.S. Congress (“Congress”) has considered and may continue to consider eliminating this regulatory exemption, which could subject hydraulic fracturing activities to regulation and permitting by the Environmental Protection Agency (“EPA”) under the SDWA. On June 28, 2016, the EPA issued final pre-treatment standards prohibiting the disposal of wastewater pollutants from on-shore unconventional oil and gas extraction facilities to publicly owned treatment works. The EPA’s regulation of hydraulic fracturing may result in our incurring additional costs to comply with such requirements that may be significant in nature. Such regulation may result in our experiencing delays or curtailment in the pursuit of exploration, development, or production activities, and we could even be prohibited from drilling and/or completing certain wells.

~~· new municipal or state land use regulations, such as changes in setback requirements, which may restrict drilling locations or related activities;~~

· financial assurance requirements, such as the posting of bonds, to secure site restoration obligations; and

· local moratoria or even bans on oil and natural gas development utilizing hydraulic fracturing in some communities.

In addition, the federal government has the authority to regulate hydraulic fracturing on federal and tribal lands. Under the Obama administration, the Bureau of Land Management (“BLM”) issued its final regulations for hydraulic fracturing on federal and tribal lands that require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. The regulations are the subject of litigation, which is still pending. At the U.S. federal level, hydraulic fracturing that does not involve the use of diesel fuels is exempt from regulation under the Safe Drinking Water Act (“SDWA”). However, the U.S. Congress (“Congress”) has considered and may continue to consider eliminating this regulatory exemption, which could subject hydraulic fracturing activities to regulation and permitting by the Environmental Protection Agency (“EPA”) under the SDWA. On June 28, 2016, the EPA issued final pre-treatment standards prohibiting the disposal of wastewater pollutants from on-shore unconventional oil and gas extraction facilities to publicly owned treatment works. The EPA’s regulation of hydraulic fracturing may result in our incurring additional costs to comply with such requirements that may be significant in nature. Such regulation may result in our experiencing delays or curtailment in the pursuit of exploration, development, or production activities, and we could even be prohibited from drilling and/or completing certain wells.

Despite the existing regulatory exemption, the EPA has begun utilizing other legal authorities in various ways to regulate portions of the hydraulic fracturing process, exemplified by its issuance of regulations under the Clean Air Act limiting emission of pollutants during the hydraulic fracturing process, as well as its recent initiation of a proposed rulemaking under the Toxic Substances Control Act to obtain data on chemical substances and mixtures used in hydraulic fracturing. In addition, the U.S. Department of the Interior has proposed comprehensive regulations governing the use of hydraulic fracturing on federally managed lands. Under the current administration, many of these regulations are under review and may be repealed or revised.

These efforts by Congress, federal regulators, states and local governments could result in additional costs, delay and operational uncertainty that could limit, preclude or add costs to use of hydraulic fracturing in our drilling operations.

Conservation measures and technological advances could reduce demand for crude oil, natural gas and NGLs.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to crude oil, natural gas and NGLs, technological advances in fuel economy and energy generation devices could reduce demand for crude oil, natural gas and NGLs. The impact of the changing demand for crude oil, natural gas and NGL services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Table of Contents

Increasing trends of opposition to oil and gas development activity and negative public perception regarding us and/or our industry could have an adverse effect on our operations.

In recent years, we have seen significant growth in anti-oil and gas development activity both in the U.S. and globally. Companies in our industry can be the target of opposition to hydrocarbon development. This opposition is focused on attempting to limit or stop hydrocarbon development in certain areas. Examples of such opposition include efforts to reduce access to public and private lands, restriction of exploration and production activities within government-owned and other lands, delaying or canceling permits for drilling or pipeline construction, limiting or banning industry techniques such as hydraulic fracturing and/or adding restrictions on the use of water and associated disposal, imposition of set-backs on oil and gas sites, delaying or denying air-quality or siting permits, advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity, and the use of social media channels to cause reputational harm.

Our need to incur costs associated with responding to these anti-development efforts, including legal challenges, or complying with any new legal or regulatory requirements resulting from these efforts, could have a material adverse effect on our business, results of operations or financial condition.

Table of Contents

Our ability to produce oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Drilling activities require the use of water. For example, the hydraulic fracturing process that we employ to produce commercial quantities of oil and natural gas from many reservoirs, including the Eagle Ford, requires 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. The effects of climate change may further exacerbate water scarcity in certain regions.

Our inability to timely 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. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on 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 oil and natural gas. In particular, regulatory focus on disposal of produced water and drilling waste through underground injection has increased because of alleged links between such injection and regional seismic impacts in disposal areas.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could materially and adversely affect our business, results of operations and financial condition.

Table of Contents

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other

“greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA have allowed the agency to proceed with the adoption and implementation of regulations restricting emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Among other things, EPA regulations now require specified large greenhouse gas emitters in the U.S., including companies in the energy industry, to annually report those emissions. New major sources or significant modifications of existing sources of traditional air pollutants are required to obtain permits and to use best available control technology to control those emissions pursuant to the Clean Air Act as a prerequisite to the development of that emissions source. In addition, sources subject to best available control technology for traditional air pollutants are now also required to use best available control technology to control significant greenhouse gas emissions. While these regulations have not to date materially affected us, such regulations may over time require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce.

In May 2016, the EPA issued final regulations intended to reduce methane emissions from the oil and gas sector by 40% to 45% from 2012 levels by 2025. On October 20, 2016, the EPA issued final Control Techniques Guidelines for reducing smog-forming VOC emissions from existing oil and natural gas equipment and processes in certain states and areas with smog problems. The Obama-era methane regulations are currently under review by the Trump administration and a rule proposing to significantly revise and rescind these requirements was published by the EPA in August 2019. The methane regulations could affect us indirectly by affecting our customer base or by directly regulating our operations.

In ~~addition~~May 2016, ~~Congress~~the ~~has~~EPA ~~considered~~issued ~~legislation~~final toregulations ~~restrict~~intended orto ~~regulate~~reduce methane emissions offrom ~~greenhouse~~the ~~gases,~~oil ~~such as carbon dioxide~~ and ~~methane~~gas ~~that~~sector ~~are~~by ~~understood~~40% to ~~contribute~~45% tofrom ~~global~~2012 ~~warming.~~levels ~~While~~by ~~comprehensive~~2025. ~~climate~~In ~~legislation~~October 2016, ~~will~~the ~~likely~~EPA ~~not~~issued befinal ~~passed~~Control byTechniques ~~either~~Guidelines ~~house~~for ofreducing ~~Congress~~smog-forming inVOC ~~the~~emissions ~~near~~from ~~future,~~existing ~~energy~~oil ~~legislation~~ and ~~other~~natural ~~initiatives~~gas ~~continue~~equipment toand beprocesses ~~proposed~~in ~~that~~certain ~~may~~states beand ~~relevant~~areas towith ~~greenhouse~~smog ~~gas emissions issues~~problems. In ~~addition~~August 2020, ~~almost~~EPA ~~half~~adopted ofderegulatory ~~the~~amendments ~~states,~~to ~~either~~the ~~individually~~2016 orrule intended ~~through~~to ~~multi-state~~streamline ~~regional initiatives~~implementation, ~~have~~reduce ~~begun~~duplicative toEPA ~~address~~and ~~greenhouse~~state ~~gas~~requirements ~~emissions,~~and ~~primarily~~decrease ~~through~~ the ~~planned~~burden ~~development~~ of ~~emission~~compliance. ~~inventories~~In orparticular, ~~regional~~the ~~greenhouse~~amendments ~~gas~~removed ~~cap~~the transmission and ~~trade~~storage ~~programs.~~segments ~~Although~~from ~~most of~~ the ~~state-level~~oil ~~initiatives~~and ~~have~~natural togas ~~date~~source ~~been~~category ~~focused~~and onrescinded ~~large~~the ~~sources~~methane-specific ofrequirements ~~greenhouse~~for ~~gas~~production ~~emissions~~and ~~such~~processing asfacilities. ~~electric~~In ~~power~~January ~~plants~~2021, ~~smaller~~the ~~sources~~administration ~~could~~issued ~~become~~an ~~subject~~executive toorder ~~greenhouse~~calling ~~gas-related regulation. Depending~~ on the ~~particular~~EPA ~~program~~to, weamong ~~could~~other bethings, ~~required~~consider toa ~~control~~proposed ~~emissions~~rule orsuspending, torevising ~~purchase~~or ~~and~~rescinding ~~surrender~~the ~~allowances~~deregulatory ~~for~~amendments ~~greenhouse~~by ~~gas~~September ~~emissions~~2021. As ~~resulting~~a ~~from~~result, ~~our~~the ~~operations. Any~~ future ~~federal~~implementation ~~laws~~of orthese ~~implementing~~standards ~~regulations~~is ~~that~~uncertain. However, ~~may~~such bemethane ~~adopted~~regulations ~~to address greenhouse gas emissions~~ could ~~require~~affect us toindirectly ~~incur~~by ~~increased~~affecting ~~operating~~our ~~costs~~customer ~~and~~base ~~could~~or ~~adversely~~by ~~affect~~directly ~~demand~~regulating ~~for~~our ~~the oil and natural gas we produce~~operations.

Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

37 43

Table of Contents

In addition, Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane that are understood to contribute to global warming. Energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions such as electric power plants, smaller sources could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

Terrorist attacks aimed at energy operations could adversely affect our business.

The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected oil and natural gas operations to increased risks. Any future terrorist attack (in the form of physical attacks or cyber-attacks) on our facilities, customer facilities, and the infrastructure depended upon for transportation of products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.

General economic conditions could adversely affect our business and future growth.

Instability in the global financial markets may have a material impact on our liquidity and financial condition, and we may ultimately face major challenges if conditions in the financial markets were to materially change or worsen. Our ability to access the capital markets or to borrow money may be restricted or may be more expensive at a time when we would need to raise capital, which could have an adverse effect on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Such economic conditions could have an impact on our customers, causing them to fail to meet their obligations to us. In addition, it could have an impact on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments.

Also, market conditions could have an impact on our oil and natural gas derivative instruments if our counterparties are unable to perform their obligations or seek bankruptcy protection, which could lead to reductions in the demand for oil and natural gas, or reductions in the prices of oil and natural gas or both, which could have an adverse impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of changing economic conditions cannot be predicted, they may materially and adversely affect our business, results of operations and financial condition.

Table of Contents

Federal legislation could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

The Dodd-Frank Act, enacted in 2010, establishes federal oversight and regulation of the OTC derivatives market and entities, like us, that participate in that market. Among other things, the Dodd-Frank Act required the Commodity Futures Trading Commission to promulgate a range of rules and regulations applicable to OTC derivatives transactions, and these rules may affect both the size of positions that we may enter or the ability and willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices. While many Dodd-Frank Act regulations are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain.

In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may become subject to or otherwise impacted by such regulations. At this time, the impact of such regulations is not clear.

Our business could be adversely impacted by security threats, including cyber-security threats, and other disruptions.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, as well as conduct reservoir modeling and reserve estimation for compliance reporting.

Table of Contents

We are dependent on digital technologies including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees, business partners, and stockholders, analyze seismic and drilling information, estimate quantities of oil and natural gas reserves as well as other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production and financial institutions are also dependent on digital technology. The technologies needed to conduct oil and natural gas exploration, development and production activities make certain information the target of theft or misappropriation.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for the purposes of misappropriating assets or sensitive information, corrupting data, causing operational disruption, or result in denial-of-service on websites.

Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period of time. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations.

~~Our ability to use our net operating loss carryforwards could be limited.~~

AsIf ~~of December 31, 2019,~~ we ~~had~~fail ~~approximately $292.4 million NOLs that we are allowed~~ to ~~carryforward~~establish ~~for~~and ~~U.S.~~maintain ~~federal~~proper ~~income~~internal ~~tax purposes. Our NOLs begin to expire in 2033. Utilization of these NOLs depends on many factors~~controls, ~~including~~ our ~~future~~ability income, which cannot be assured. In addition, Section 382 of the Code generally imposes an annual limitation on the amount of taxable income that may be offset by NOLs when a corporation has undergone an “ownership change” (as determined under Section 382 of the Code). Generally, a change in more than 50% of the ownership of a corporation’s stock, by value, over a three-year period constitutes an ownership change for U.S. federal income tax purposes. Any unused limitation may be carried forward to ~~future~~produce ~~taxable~~accurate ~~years.~~financial Westatements believe that $206.2 million of our NOLs will expire unused as a result of the Section 382 limitation that resulted from a change in ownership occurring in conjunction with to our 2018 equity issuance. In addition, future ownership changes or ~~regulatory~~comply ~~changes could further limit our ability to utilize any NOLs. To the extent we are not able to offset our future income~~ with ~~NOLs,~~applicable ~~this~~regulations could ~~adversely~~be ~~affect our operating results and cash flows~~impaired.

~~Ineffective internal controls could impact our business and financial results.~~

We are subject to Section 404(a) of the Sarbanes-Oxley Act, which requires that our management assess and report annually on the effectiveness of our internal controls over financial reporting and identify any material weaknesses in our internal controls over financial reporting. Although Section 404(b) of the Sarbanes-Oxley Act requires our independent registered public accounting firm to issue an annual report that addresses the effectiveness of our internal controls over financial reporting, we have opted to rely on the exemptions provided in the Jumpstart Our Business Startups Act (the “JOBS Act”), and consequently will not be required to comply with SEC rules that implement Section 404(b) of the Sarbanes-Oxley Act until such time as we are no longer an emerging growth company.

In connection with the preparation of this annual report, management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2019 and concluded that there was a material weakness related to deferred tax assets and the related valuation allowance, specifically related to the conversion of our historical financial statements from International Financial Reporting Standards (“IFRS”) to U.S. GAAP as a result of our Redomiciliation to the U.S. For additional information regarding the material weakness identified please see “Part II, Item 9A — Controls and Procedures” of this annual report.

If additional material weaknesses in internal control over financial reporting are discovered or occur in the future, it could lead to errors in our financial reports and/or delays in our financial reporting, which could require us to restate our operating results and investors may lose confidence in our operating results, the price of our shares could decline and we may be subject to litigation or regulatory enforcement actions. 45

Table of Contents

Our management has concluded that our internal controls over financial reporting were effective as of December 31, 2020. However, if we fail to maintain effective internal controls over financial reporting in the future, the presence of material weaknesses could result in financial statement errors which, in turn, could lead to errors in our financial reports and/or delays in our financial reporting, which could require us to restate our operating results or our auditors may be required to issue a qualified audit report.

In addition, if we are unable to conclude that we have effective internal controls over financial reporting, investors may lose confidence in our operating results, the price of our shares could decline and we may be subject to litigation or regulatory enforcement actions.

We might not identify one or more material weaknesses in our internal controls in connection with evaluating our compliance with Section 404(a) of the Sarbanes-Oxley Act. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal controls over financial reporting, we will need to expend significant resources and provide significant management oversight. Implementing any appropriate changes to our internal controls may require specific compliance training of our directors and employees, entail substantial costs in order to modify our existing accounting systems, take a significant period of time to complete and divert management’s attention from other business concerns. These changes may not, however, be effective in maintaining the adequacy of our internal control.

~~We are an emerging growth company, and we cannot be certain if the reduced reporting requirements applicable to emerging growth companies will make our common stock less attractive to investors.~~

We are an emerging growth company, as defined in the JOBS Act. For as long as we continue to be an emerging growth company, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We expect to continue to take advantage of some or all of the available exemptions.

Risks Related with the Redomiciliation

The expected benefits of the Redomiciliation may not be realized.

We cannot be assured that the anticipated benefits of the Redomiciliation will be achieved, particularly those subject to factors beyond our control. These factors include such things as the reactions of third parties with whom we do business and the reactions of investors, analysts and Australian and U.S. taxing authorities. If events or changes in circumstances occur affecting the aforementioned factors, we may not be able to continue to realize the expected logistical and operational benefits of the Redomiciliation.

We have incurred additional costs as a result of the Redomiciliation and we expect to continue to do so.

The Redomiciliation has resulted in an increase in some of our ongoing expenses and may require us to incur some new expenses, including professional fees, to comply with applicable U.S. corporate and tax laws.

Risks Related to Our Common Stock

~~The price of our common stock has been and may continue to be highly volatile, which may make it difficult for stockholders to sell our common stock when desired or at attractive prices.~~

~~Following~~The ~~our~~shares ~~Redomiciliation, the trading price~~ of our existing common stock ~~has been volatile, and could be subject to fluctuations in response to various factors, some of which~~ are ~~beyond~~expected ~~our control. Factors such as announcements of variations in our quarterly financial results and fluctuations in revenue could also cause the market price of our common stock~~ to fluctuate. Additionally, the stock markets have at times experienced price and volume fluctuations that have affected and might in the future affect the market prices of equity securities of many companies. These fluctuations have, in some cases, been unrelated or disproportionate to the operating performance of these companies. Further, the trading prices of publicly traded shares of companies in our industry have been particularly volatile and may be ~~very~~canceled ~~volatile~~ in the future. These broad market and industry fluctuations, as well as general economic, political and market conditions such as recessions, interest rate changes, international currency fluctuations or political unrest, may negatively impact the market price of our ~~common~~Chapter ~~stock.~~11 ~~If the price of our common stock declines, our ability to raise funds through the issuance of equity or otherwise use our common stock as consideration will be reduced~~proceedings. ~~A low price for our equity may negatively impact our ability to access additional debt capital. These factors may limit our ability to implement our operating and growth plans.~~

~~Table~~We have a significant amount of ~~Contents~~ indebtedness that is senior to our existing common stock in our capital structure. As a result, in accordance with our Prepackaged Plan, the existing shares of our common stock are expected to be canceled in our Chapter 11 proceedings and are not expected to be entitled to any recovery. Any trading in shares of our common and preferred stock during the pendency of the Chapter 11 proceedings is highly speculative and poses substantial risks to purchasers of shares of our common stock. Upon our emergence from bankruptcy, our existing common stock will be canceled and removed from further trading by the Financial Industry Regulatory Authority.

~~We have never declared or paid dividends on our common stock and we do not anticipate paying dividends in the foreseeable future.~~

We have never declared or paid cash dividends on our common stock. For the foreseeable future, we currently intend to retain all available funds and any future earnings to support our operations and to finance the growth and development of our business. Any future determination to declare cash dividends will be made at the discretion of our board of directors, subject to compliance with applicable laws and covenants under current or future credit facilities, which may restrict or limit our ability to pay dividends, and will depend on our financial condition, operating results, capital requirements, general business conditions and other factors that our board of directors may deem relevant. We do not anticipate paying any cash dividends on our common stock in the foreseeable future. As a result, a return on your investment will only occur if the price of our common stock appreciates.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Information regarding our oil and gas properties is included in Part I, Item 1. “Business” under “Oil and Natural Gas Properties”. We also lease approximately 19,000 square feet of office space at 1050 17th Street, Suite 700, Denver, Colorado 80265, where our principal offices are located. We also have various operating leases for rental of field office space, office and field equipment, and vehicles. See Note 6 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” for the future minimum rental payments. Such information is incorporated herein by reference.

Information regarding our oil and gas properties is included in Part I, Item 1. “Business” under “Oil and Natural Gas Properties”. We also lease approximately 19,000 square feet of office space at 1050 17th Street, Suite 700, Denver, Colorado 80265, where our principal offices are located. We also have various operating leases for rental of field office space, office and field equipment, and vehicles. See Note 5 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” for the future minimum rental payments. Such information is incorporated herein by reference.

Item 3. Legal Proceedings.

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and natural gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety, and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial position, cash flows or results of operations.

For discussion of our ongoing bankruptcy proceedings, see Part I, Item 1. Business subsection Bankruptcy Proceedings under Chapter 11.

Table of Contents

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market

~~Our common stock is traded on the Nasdaq Global Market under the symbol “SNDE”. As of April 24, 2020, there were 4,169 holders of record of our common stock.~~

41 Our common stock was previously listed and traded on the Nasdaq Global Market (the “Nasdaq”) under the symbol “SNDE”. As a consequence of the Chapter 11 Cases, beginning March 19, 2021, our ordinary shares were trading on the OTC Pink Open Market under the symbol SNDEQ. On March 22, 2021 there were 3,845 holders of record of our common stock.

~~Table of Contents~~

Dividend Policy

We currently intend to retain any earnings to fund the operation and expansion of our business and do not anticipate paying any cash dividends on our common stock for the foreseeable future. The declaration and payment of any dividends in the future by us will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors. Moreover, if we determine to pay any dividend on common stock in the future, there can be no assurance that we will continue to pay such dividends. In addition, under our debt agreements, we are not permitted to pay cash dividends on our common stock without the prior written consent of our lenders.

We will not pay dividends during the pendency of our Chapter 11 proceedings. In accordance with our Prepackaged Plan, the existing shares of our common stock are expected to be canceled in our Chapter 11 proceedings and existing shareholders are not expected to be entitled to any recovery. Any trading in shares of our common stock during the pendency of the Chapter 11 proceedings is highly speculative and poses substantial risks to purchasers of shares of our common stock. Upon our emergence from bankruptcy, our existing common stock will be canceled and removed from further trading by the Financial Industry Regulatory Authority.

Item 6. Selected Financial Data.

Not applicable.

~~Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations~~

~~The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Part II,~~ Item 87. ~~“Financial~~Management’s ~~Statements~~Discussion and ~~Supplementary~~Analysis ~~Data”~~ of ~~this~~Financial ~~annual~~Condition ~~report. Our discussion~~ and ~~analysis~~Results includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Part I, Item 1A. “Risk Factors” along with “Cautionary Statement Regarding Forward-Looking Statements” on page 2 of ~~this annual report for information on the risks and uncertainties that could cause our actual results to be materially different from our forward-looking statements.~~ Operations

~~Overview and Executive Summary~~

WeThe ~~are~~following andiscussion ~~onshore~~and ~~independent~~analysis ~~oil~~should ~~and~~be ~~natural~~read ~~gas~~in ~~company~~conjunction ~~focused~~with onour ~~the~~Consolidated ~~development,~~Financial ~~production~~Statements and ~~exploration~~Notes ofthereto ~~large,~~included ~~repeatable~~in ~~resource~~Part ~~plays~~II, inItem ~~North America~~8. ~~Our~~“Financial ~~operations~~Statements ~~are~~and ~~located~~Supplementary inData” ~~the~~of ~~Eagle~~this ~~Ford~~annual ~~formation in south Texas~~report. Our ~~strategy~~discussion isand toanalysis ~~acquire~~includes ~~and/or~~forward-looking ~~develop~~information ~~assets~~that ~~where~~involves werisks ~~are~~and ~~operator~~uncertainties and ~~have~~should ~~high~~be ~~working~~read ~~interests,~~in ~~positioning~~conjunction uswith toPart ~~efficiently~~I, ~~control~~Item ~~the~~1A. ~~pace~~“Risk ~~and~~Factors” ~~scope~~along ofwith ~~our~~“Cautionary ~~development~~Statement ~~and~~Regarding ~~the~~Forward-Looking ~~allocation~~Statements” ofon ~~our~~page ~~capital~~2 ~~resources.~~of Wethis ~~also~~annual ~~believe~~report ~~that~~for ~~serving~~information ason ~~operator allows us to control~~ the ~~drilling,~~risks ~~completion, operations~~ and ~~marketing~~uncertainties ofthat ~~sold~~could ~~volumes. In~~cause ~~2019,~~our weactual ~~continued~~results to ~~focus~~be onmaterially ~~developing~~different ~~high-return assets~~ from our ~~portfolio~~forward-looking ~~while reducing our operating costs and per well drilling and completion costs~~statements.

~~We took the following actions during 2019 in support of our corporate strategy:~~

·Overview ~~On November 26, 2019, we successfully redomiciled to the U.S. from Australia,~~ and ~~our~~Executive ~~common stock began trading on the Nasdaq Global Market, under the ticker symbol “SNDE”.~~Summary

· We completed and had initial production from 22 net operated wells (two of which were subsequently sold during October 2019), which increased our average daily net production 38% from 2018 to 13,248 Boe/d.

·We Inare ~~October~~an ~~2019,~~onshore weindependent ~~completed~~oil and natural gas company focused on the ~~divestiture~~development, production and exploration of 19large, ~~gross~~repeatable ~~producing~~resource ~~wells~~plays ~~located~~in onNorth ~~approximately~~America. ~~6,100~~Our ~~net~~operations ~~acres~~are located in ~~Dimmit~~the ~~County,~~Eagle Ford formation in south Texas. Our ~~for~~strategy ~~proceeds~~is to acquire and/or develop assets where we are operator and have high working interests, positioning us to efficiently control the pace and scope of ~~$21~~our development and the allocation of our capital resources.5 ~~million,~~Serving ~~including~~as ~~effective~~operator ~~date~~allows us to ~~closing~~control ~~date~~the ~~adjustments~~drilling, ~~less~~completion, ~~transaction~~operations, ~~costs~~and marketing of ~~$0.5~~sold ~~million~~volumes. ~~Sales~~As ~~volumes~~a ~~from~~result ~~these~~of ~~wells~~the ~~was~~sharp ~~approximately~~decline ~~1,153~~in ~~Boe/d~~commodity price s during the first ~~nine~~quarter ~~months~~of 2020 and the impact on our financial position, we significantly decreased our level of ~~2019~~capital spending. Upon ~~The~~emergence ~~divesture~~from ~~provided~~bankruptcy ~~additional~~(described ~~liquidity~~below under Recent Events), we plan to ~~allow~~continue ~~development~~to offocus ~~our~~on ~~higher~~developing high-return assets from our portfolio, while preserving an attractive oil-rich inventory.

· In January 2020, we amended our Revolving Facility to increase the overall facility from $250 million to $500 million, and to increase our borrowing base to $210 million (with initial elected borrowing commitments of $190 million). We are currently restricted in our ability to make draws until the finalization of our second quarter borrowing base redetermination. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Credit Facilities” for additional information regarding our credit facilities.

42 Recent Events

~~Table of Contents~~

~~Business~~On March 9, 2021, Sundance and ~~Industry~~its ~~Outlook~~ subsidiaries commenced the Chapter 11 Cases under Chapter 11 of the Bankruptcy Code.

Market prices for crude oil, natural gas and NGLs are inherently volatile. In 2019, WTI oil prices averaged approximately $56.98 per Bbl versus $65.23 per Bbl in 2018. Despite price support in the first half of 2019 driven by supply tightness, geopolitical tensions, 2019 WTI oil prices overall were negatively impacted by trade concerns and economic slowdown fears. In March 2020, NYMEX WTI oil prices declined sharply to less than $20 per Bbl and in April 2020, for a short period of time were negative, primarily due to drastic price cutting and increased production by Saudi Arabia coupled with an expected demand reduction caused by the global COVID-19 outbreak. The U.S. domestic natural gas market remains oversupplied as production has continued to grow due to drilling efficiencies, higher incremental volumes of associated gas from oil wells and de-bottlenecking of transportation infrastructure. Henry Hub gas prices averaged approximately $2.56 per MMBtu in 2019 versus $3.15 per MMBtu in 2018. Natural gas and NGL prices faced strong headwinds in 2019 due to U.S. supply growth far outpacing demand for both commodities domestically and internationally. These factors continue to weigh on natural gas and NGL prices. To mitigate our exposure to commodity price volatility and ensure our financial strength, we continue to execute a hedging program. 47

WeTable ~~expect capital expenditures to be in the range~~ of $40 - $45 million for 2020. However, we intend to flexibly manage our operations, including capital expenditure levels, based on existing and expected market conditions to protect our balance sheet and retain liquidity. We expect to be able to fund our planned capital program for 2020 with cash flow generated from operating activities (which includes proceeds from settlements of hedging contracts) and cash on hand. As of the date of this annual report, we also had $58.6 million available under our Revolving Facility. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Cash flows used in investing activities” for further discussion of our capital expenditures. Contents

~~Year~~On ~~Ended~~March ~~December 31~~9, ~~2019~~2021, ~~Compared~~we entered into a RSA with (i) Toronto Dominion (Texas) LLC, as agent pursuant to the ~~Year~~ ~~Ended~~Revolving ~~December~~Facility, (ii) the lenders party to that certain Credit Agreement, dated as of July 18, 2018 (as amended, modified, or supplemented), (iii) 31Morgan Stanley Capital Administrators Inc. as agent pursuant to the Term Loan Facility, and (iv) the lenders party to that certain Amended & Restated Term Loan Credit Agreement, dated as of April 23, 2018 (as amended, modified, or supplemented from time to time) to support a reorganization in accordance with the terms set forth in the Plan.

~~Revenues and Sales Volume. The following table provides the components of our revenues for the years ended December 31, 2019 and 2018, as well as each period’s respective sales volumes:~~

	Year ended
	December 31,
Revenue (In $ ’000s):	2019		2018		Change in $		Change as %
Oil sales	$	177,853	$	140,240	$	37,613	27
Natural gas sales		12,553		12,025		528	4
NGL sales		13,174		12,668		506	4
Product revenue	$	203,580	$	164,933	$	38,647	23

Due to the Chapter 11 Cases, the Company’s common stock was delisted from NASDAQ on March 19, 2021 and began trading on the Pink Open market under the symbol “SNDEQ”.

	Year ended
	December 31,
Net sales volumes:	2019	2018	Change in Volume	Change as %
Oil (Bbls)	3,076,582	2,256,043	820,539	36
Natural gas (Mcf)	5,767,779	4,533,604	1,234,175	27
NGL (Bbls)	797,784	496,624	301,160	61
Oil equivalent (Boe)	4,835,663	3,508,268	1,327,395	38
Average daily production (Boe/d)	13,248	9,612	3,636	38

We expect to continue operations in the normal course for the duration of the Chapter 11 Cases. To ensure ordinary course operations, we have obtained approval from the Bankruptcy Court for certain “first day” motions, including motions to obtain customary relief intended to minimize the impact of the Chapter 11 Cases on our operations, customers and employees. Upon emergence from bankruptcy, we expect that we will no longer be a publicly traded company. For more information on the Chapter 11 Cases and related matters, please see Note 15—Subsequent Events in Part II, Item 8. “Financial Statements and Supplementary Data”.

Boe and average net daily production. Sales volumes increased by 1,327,395 Boe (3,636 Boe/d) to 4,835,663 Boe (13,248 Boe/d) for the year ended December 31, 2019 compared to 3,508,268 Boe (9,612 Boe/d) for the prior year primarily due to our 2019 and 2018 drilling programs, which was back-loaded in the second half of 2018, partially offset by normal field production declines and downtime resulting from midstream capacity constraints, well equipment failure and simultaneous operations. We had initial production from 22 net operated wells in 2019 and 20 net operated wells in the second half of 2018.

43 Business and Industry Outlook

~~Table of Contents~~

~~Beginning~~During in2020, ~~the~~WTI ~~fourth~~oil ~~quarter~~spot prices ranged from a high of ~~2018~~$63.27 ~~through~~in ~~May~~January ~~2019~~and briefly dropped below zero in April 2020, weprimarily ~~experienced~~due ~~capacity~~to ~~constraints~~drastic atprice cutting and increased production by Saudi Arabia coupled with a ~~midstream~~demand ~~facility. We~~reduction ~~and~~caused ~~our~~by ~~midstream~~the ~~partner~~global ~~completed~~COVID-19 pandemic. In the ~~first~~second ~~phase~~half of a2020, ~~capacity~~WTI ~~expansion~~oil ofspot ~~the~~prices slowly rebounded and hovered near $40 per barrel. While market prices for crude oil, natural gas ~~processing~~and ~~plant~~NGLs ~~through~~are inherently volatile, the ~~installation~~increase ofin ~~two~~supply ~~additional~~and ~~compressors~~decrease in ~~May~~demand ~~2019~~to historic extremes has impacted our entire industry. In Given the ~~fourth~~dynamic ~~quarter~~nature of ~~2019~~these macroeconomic conditions, ~~our~~we ~~midstream~~are ~~partner~~unable ~~commenced~~to anreasonably ~~additional~~estimate ~~expansion~~the ~~project~~period toof ~~ensure~~time ~~capacity~~that ~~for~~these ~~future~~market ~~development. The~~conditions ~~second~~will ~~phase~~exist and the extent of the ~~expansion~~impact ~~project~~they ~~was~~will ~~completed~~have inon ~~the~~our ~~first~~business, ~~quarter~~liquidity, results of ~~2020~~operations, financial condition, or the timing of any subsequent recovery.

Our sales volume is oil‐weighted, with oil representing 64% of total sales volume for both the years ended December 31, 2019 and 2018, and liquids (oil and NGLs) representing 80% and 78% of total sales volumes for the years ended December 31, 2019 and 2018, respectively. Our oil sales and liquid sales volumes as a percentage of total sales volumes was lower in 2019 than what we expect it to be prospectively primarily due to the gassier sales volumes produced from our Dimmit County assets, which were divested in October 2019.

~~Oil~~The ~~sales.~~sharp ~~Oil~~decline ~~sales~~in ~~increased~~commodity byprices ~~$37.6~~and ~~million~~lower ~~(27%)~~expectations tofor ~~$177.9~~near-term ~~million~~commodity ~~for~~prices, ~~the~~has ~~year~~reduced ~~ended~~our ~~December~~revenue ~~31,~~and ~~2019~~cash flow from ~~$140.2~~operations ~~million~~and ~~for~~slowed the ~~prior~~pace ~~year.~~at ~~The~~which ~~increase~~we incan ~~oil~~develop ~~revenue~~our ~~was~~oil ~~driven~~and bynatural ~~higher~~gas ~~sales volumes ($51~~assets.0 ~~million)~~In addition, ~~offset~~substantial byand ~~lower~~extended ~~product~~declines ~~pricing~~in ~~($13.4~~oil, ~~million). The~~natural ~~average~~gas ~~realized~~and ~~price~~NGL onprices reduces the ~~sale~~amount of ~~our~~ oil ~~decreased~~and bynatural 7%gas tothat ~~$57.81~~we ~~per~~can ~~Bbl~~produce ~~for the year ended December 31~~economically, ~~2019~~which (ahas ~~$0.83~~reduced ~~premium~~our tooil ~~the~~and ~~average~~gas ~~WTI~~reserve ~~price~~quantities ~~for~~and ~~the~~resulted, ~~same~~and ~~period)~~may ~~from~~result, ~~$62.16~~in ~~per~~impairment ~~Bbl~~of ~~for~~our ~~the~~proved ~~prior year. We are able to sell~~ oil atand agas ~~premium~~properties to(such ~~WTI~~as ~~due~~the toimpairment ~~our~~discussed ~~proximity~~under toResults ~~Gulf~~of ~~Coast~~Operations ~~refining~~ and ~~export~~Note ~~markets~~2). ~~Oil~~ It ~~sales~~has ~~volumes~~also ~~increased~~impacted ~~36%~~our ability to ~~3,076,582~~comply ~~Bbls~~with ~~for~~certain ~~the~~financial ~~year~~covenants ~~ended~~required ~~December~~by ~~31,~~our ~~2019~~credit ~~compared~~facilities to(as ~~2,256,043~~described ~~Bbls~~further ~~for~~under ~~the~~Note ~~prior year~~6).

Natural gas sales. Natural gas sales increased by $0.5 million (4%) to $12.6 million for the year ended December 31, 2019 from $12.0 million for the prior year. The increase in natural gas revenues was the result of higher sales volumes ($3.2 million), partially offset by lower product pricing ($2.7 million). Natural gas sales volumes increased 27% to 5,767,779 Mcf for the year ended December 31, 2019 compared to 4,533,604 Mcf for the prior year. The average realized price on the sale of our natural gas decreased by 18% to $2.18 per Mcf (net of certain transportation and marketing costs) for the year ended December 31, 2019 from $2.65 per Mcf for the prior year. 48

~~NGL~~Table ~~sales. NGL sales increased by $0.5 million (4%) to $13.2 million for the year ended December 31, 2019 from $12.7 million for the prior year. The increase in NGL revenues was the result~~ of higher sales volumes ($7.7 million), offset by lower product pricing ($7.2 million). NGL sales volumes increased 301,160 Bbls (61%) to 797,784 Bbls for the year ended December 31, 2019 compared to 496,624 Bbls for the prior year. The average realized price on the sale of our NGLs decreased by 35% to $16.51 per Bbl for the year ended 31 December 2019 from $25.51 per Bbl for the prior year. Contents

~~The~~Year ~~following~~Ended ~~table~~December 31, ~~provides~~2020 aCompared ~~summary~~to ofthe Year ~~our~~Ended ~~operating~~December 31, ~~expenses~~2019 ~~on a per BOE basis:~~

	Year ended December 31,
Selected per Boe metrics	2019		2018		Change		Change as %
Total oil, natural gas and NGL revenues	$	42.10	$	47.01	$	(4.91)	(10)
Lease operating expense (1)		(5.85)		(8.04)		2.19	27
Workover expense (1)		(1.11)		(1.64)		0.53	32
Gathering, processing and transportation expense		(3.53)		(2.46)		(1.07)	(44)
Production taxes		(2.37)		(2.64)		0.27	10
Depreciation, depletion and amortization (2)		(18.96)		(17.78)		(1.18)	(7)
General and administrative expense		(4.61)		(8.70)		4.09	47

~~(1)~~Revenues ~~Lease~~and ~~operating~~Sales ~~expense~~Volume. ~~and~~The ~~workover~~following ~~expense~~table ~~are~~provides ~~included~~the ~~together~~components inof ~~lease~~our ~~operating~~revenues for the years ended December 31, 2020 and ~~workover~~2019, ~~expenses~~as onwell ~~the~~as ~~consolidated~~each ~~statement~~period’s ofrespective ~~operations.~~sales volumes:

~~(2) Excludes depreciation related to corporate assets.~~


	Year ended
	December 31,
Revenue (In $ ’000s):	2020		2019		Change in $		Change as %
Oil sales	$	76,533	$	177,853	$	(101,320)	(57)
Natural gas sales		7,887		12,553		(4,666)	(37)
NGL sales		7,392		13,174		(5,782)	(44)
Product revenue	$	91,812	$	203,580	$	(111,768)	(55)

~~Table of Contents~~

Lease operating expense. Our LOE increased by $0.1 million (less than 1%) to $28.3 million for the year ended December 31, 2019 from $28.2 million in the prior year, and decreased $2.19 per Boe to $5.85 per Boe from $8.04 per Boe. In addition to realizing economies of scale on some of our fixed LOE costs, we implemented several cost saving initiatives in early 2019 primarily focused on labor, automating measurements through supervisory control and data acquisition (“SCADA”) and compression, which have resulted in lower LOE on a per Boe basis.


	Year ended
	December 31,
Net sales volumes:	2020	2019	Change in Volume	Change as %
Oil (Bbls)	2,104,758	3,076,582	(971,824)	(32)
Natural gas (Mcf)	3,969,000	5,767,779	(1,798,779)	(31)
NGL (Bbls)	539,828	797,784	(257,956)	(32)
Oil equivalent (Boe)	3,306,086	4,835,663	(1,529,577)	(32)
Average daily sales volumes (Boe/d)	9,033	13,248	(4,215)	(32)

Workover expense. Our workover expenses decreased $0.4 million to $5.4 million for the year ended December 31, 2019, as compared to $5.8 million for the year ended December 31, 2018. Workover expense per Boe decreased $0.53 to $1.11 per Boe for the year ended December 31, 2019 as compared to the prior year. The increased sales volumes have diluted the workover costs on a per unit basis due to the wells being brought online recently having higher production, but requiring less workovers.

~~Gathering,~~Boe ~~processing~~ and ~~transportation~~average ~~expense~~net ~~(“GP&T”)~~daily production. ~~GP&T~~Due ~~increased~~to bythe ~~$8.5~~significant ~~million~~decline ~~(98%)~~in tooil ~~$17.1~~prices ~~million~~in ~~($3.53~~early ~~per~~2020 ~~Boe)~~and ~~for~~capital ~~the~~spending ~~year~~limitations ~~ended~~included ~~December~~in 31our recent credit agreements amendments, ~~2019~~we scaled back our 2020 drilling program as compared to ~~$8.6~~the ~~million~~development programs in 2019 and 2018 ($2which was back-loaded).46 As ~~per~~a result, sales volumes decreased by 1,529,577 Boe (4,215 Boe/d) to 3,306,086 Boe (9,033 Boe/d) for the year ended December 31, ~~2018.~~2020 ~~GP&T~~compared ~~fees~~to ~~are~~4,835,663 ~~primarily~~Boe ~~incurred~~(13,248 onBoe/d). Production ~~production~~was ~~from~~higher ~~the~~in ~~properties~~2019 wedue ~~acquired~~to more wells coming onto production in ~~April~~late 2018~~. Approximately~~ ~~$14.7~~and ~~million~~early ~~and~~2019 $5(11.90 ~~million~~new ofwells ~~the~~coming ~~GP&T~~online ~~expense~~in ~~was~~the ~~incurred~~fourth inquarter ~~normal~~of ~~course~~2018 ~~under~~and ~~various~~22.0 ~~midstream~~new ~~agreements~~operated ~~for~~wells ~~the~~in ~~years~~2019) ~~ended~~compared ~~December~~to ~~31,~~late 2019 and ~~2018,~~2020 ~~and~~(2.0 ~~the~~wells ~~remainder~~coming ofonline in the ~~expense~~fourth ~~was~~quarter ~~related~~of to2019 ~~MRC~~and ~~shortfalls,~~8.0 asoperated ~~discussed~~wells ~~below~~came online in 2020). The ~~Through~~2019 ~~our~~period ~~development~~included approximately 1,153 Boe/d of sales ~~volumes~~volume from the ~~acquired~~Dimmit County assets, ~~have~~which ~~increased~~were ~~140%~~sold in ~~2019~~October ~~as compared to 2018~~2019.

~~Certain of our midstream agreements contain MRCs related to fees due on~~ Our sales volume is oil‐weighted, with oil representing 64% ~~natural gas and NGL volumes gathered, processed and/or transported. Under the terms~~ of the contracts, if we fail to pay fees equal to or greater than the MRC under any of the contracts, we are required to pay a deficiency payment equal to the shortfall. Our MRC commitment totaled $15.8 million total sales volume and ~~$11.1~~liquids ~~million~~(oil ~~for the years ended December 31, 2019~~ and ~~2018, respectively. The shortfall totaled $2.3 million ($0.49 per Boe~~NGLs) ~~and~~representing ~~$2.8~~80% ~~million ($0.79 per Boe)~~ for both the years ended December 31, ~~2019~~ 2020 and ~~2018, respectively~~ 2019. ~~We do not expect to meet the minimum revenue commitment in 2020 at the current pace of drilling. See Part I, Item 1. “Business” under “Delivery Commitments” for additional information.~~

Production taxes. Our production taxes increased by $2.2 million (24%) to $11.5 million for the year ended December 31, 2019 from $9.3 million for the prior year, which was driven by our overall increase in production. Production taxes were 5.6% of total revenue for both the years ended December 31, 2019 and 2018.

~~Depletion,~~Oil ~~depreciation~~sales. ~~and~~Oil ~~amortization~~sales ~~expense~~decreased by $101.3 million (~~“DD&A”~~57%) to $76. ~~Our~~5 ~~DD&A~~million ~~expense~~for ~~related~~the toyear ~~proved~~ended ~~oil~~December ~~and~~31, ~~natural~~2020 ~~gas~~from ~~properties~~$177.9 ~~increased~~million for the prior year. The decrease in oil revenue was driven by lower sales volumes ($2956.32 million), coupled with lower product pricing (~~47%~~$45.1 million). The average realized price on the sale of our oil decreased by 37% to $9136.736 ~~million~~per Bbl for the year ended December 31, ~~2019~~2020 from $6257.481 ~~million~~per Bbl for the prior year. On aOil ~~per~~sales ~~Boe~~volumes ~~basis,~~decreased ~~DD&A~~32% ~~increased~~ to ~~$18.96~~2,104,758 ~~per~~Bbls ~~Boe~~ for the year ended December 31, ~~2019~~2020 compared to ~~$17.78~~3,076,582 ~~per~~Bbls ~~Boe~~for inthe ~~2018~~prior year.

Impairment expense. We recorded impairment expense of $10.0 million and $43.8 million for the years ended December 31, 2019 and 2018, respectively related to our Dimmit County oil and gas properties, which were classified as held for sale through 2018 until they were divested in October 2019. Impairment expense was recorded to reduce the carrying value to the estimated net sales proceeds, less the costs to sell the assets. We continued to extract oil and gas from the assets while held for sale, although in accordance with accounting standards, we did not record DD&A for assets classified as held for sale.

~~General~~Natural &gas ~~Administrative~~sales. ~~expense~~Natural ~~(“G&A”).~~gas ~~G&A~~sales decreased by $84.37 million (2737%) to $227.39 million for the year ended December 31, ~~2019~~2020 asfrom ~~compared to~~ $3012.56 million for the prior year. ~~2018~~The ~~G&A~~decrease ~~included~~in ~~one-time~~natural ~~transaction~~gas ~~costs~~revenues ~~related~~was tothe ~~our~~result ~~Eagle~~of ~~Ford~~lower ~~acquisition~~sales ~~totaling~~volumes ($123.49 million), orcombined ~~$3.53~~with ~~per~~lower ~~Boe. During~~product ~~2019,~~pricing we($0.8 ~~incurred~~million). ~~one-time~~Natural ~~costs,~~gas ~~primarily~~sales ~~legal~~volumes ~~and~~decreased ~~accounting~~31% ~~fees,~~ to ~~complete~~3,969,000 ~~our~~Mcf ~~redomiciliation~~for to the ~~U.S~~year ofended ~~$2.7~~December ~~million~~31, or2020 ~~$0.55~~compared ~~per~~to ~~Boe. G&A~~5,767,779 ~~excluding~~Mcf for the ~~costs~~prior ~~associated~~year. ~~with~~The ~~these~~average ~~discrete~~realized ~~transaction,~~price ~~increased~~ on anthe ~~absolute~~sale ~~basis~~of asour ~~compared~~natural togas ~~prior~~decreased ~~year~~by ~~primarily~~9% ~~due~~ to ~~higher salary and salary-related expense (~~$1.299 ~~million), as we have increased our in-house technical staff since our Eagle Ford acquisition in 2018. G&A on a~~ per ~~Boe~~Mcf ~~basis,~~(net ~~excluding~~of ~~the~~certain ~~discrete~~transportation ~~transactions~~and ~~discussed~~marketing ~~above,~~costs) ~~decreased to $4.05 per Boe~~ for the year ended December 31, ~~2019~~2020 asfrom ~~compared to~~ $52.1718 per ~~Boe~~Mcf for the ~~year~~prior ~~ended December 31, 2018~~year.

45 NGL sales. NGL sales decreased by $5.8 million (44%) to $7.4 million for the year ended December 31, 2020 from $13.2 million for the prior year. The decrease in NGL revenues was the result of lower sales volumes ($4.3 million), combined with lower product pricing ($1.5 million). NGL sales volumes decreased 257,956 Bbls (32%) to 539,828 Bbls for the year ended December 31, 2020 compared to 797,784 Bbls for the prior year. The average realized price on the sale of our NGLs decreased by 17% to $13.69 per Bbl for the year ended December 31, 2020 from $16.51 per Bbl for the prior year.

~~Table of Contents~~ 49

~~Gain/loss~~Table ~~on commodity derivative financial instruments. Our commodity derivative contracts are marked to market at the end~~ of each reporting period with the changes in fair value being recognized as gain (loss) on commodity derivative financial instruments, net. Cash flow, however, is only impacted by the monthly settlements paid to or received by the counterparty, which are also recorded as gain(loss) on commodity derivative financial instruments, net. We had a loss on derivative financial instruments of $20.5 million for the year ended December 31, 2019 as compared to a $40.2 million gain in the prior year. In 2019, the loss on commodity hedging consisted of $31.6 million of unrealized losses on commodity derivative contracts and $11.1 million of realized gains on commodity derivative contracts. The prior year gain on commodity hedging consisted of $40.8 million of unrealized gains on commodity derivative contracts and $0.6 million of realized losses on commodity derivative contracts. Contents

~~Interest expenses, net of amounts capitalized.~~ The ~~components~~following oftable ~~interest~~provides ~~expense,~~a ~~net~~summary of ~~amounts~~our ~~capitalized~~operating ~~was~~expenses ason ~~follows~~a ~~(in~~per ~~thousands)~~BOE basis:

	Year ended December 31,
Interest Expense	2019	2018	Change in $	Change as %
Interest expense on Term Loan, Revolving Facility and other	32,720	24,264	8,456	35
Amortization of debt issuance costs	3,351	2,281	1,070	47
Expense incurred with debt modification	—	1,121	(1,121)	(100)
Loss on interest rate swap	4,270	2,435	1,835	75
Capitalized interest	(2,283)	(1,470)	(813)	55
Total	38,058	28,631	9,427	33

The increase in interest expense on our Term Loan, Revolving Facility and other for the year ended December 31, 2019 as compared to the year ended December 31, 2018 was driven by the increase in the average amount of outstanding debt, slightly offset by a decrease in market interest rates. Our weighted average debt outstanding during 2019 was $347 million versus $250 million for 2018. Our weighted average effective cash interest rate was 9.2% during 2019 compared to 9.7% during 2018.


	Year ended December 31,
Selected per Boe metrics	2020		2019		Change
Total oil, natural gas and NGL revenues (price received)	$	27.77	$	42.10	$	(14.33)
Effect of commodity derivatives on average price		15.25		2.29		12.96
Total oil, natural gas and NGL revenues (price realized)	$	43.02	$	44.39	$	(1.37)
Lease operating expense (1)	$	(6.80)	$	(5.85)	$	(0.95)
Workover expense (1)	$	(0.82)	$	(1.11)	$	0.29
Gathering, processing and transportation expense	$	(6.15)	$	(3.53)	$	(2.62)
Production taxes	$	(1.65)	$	(2.37)	$	0.72
Depreciation, depletion and amortization (2)	$	(23.83)	$	(18.96)	$	(4.87)
General and administrative expense	$	(6.70)	$	(4.61)	$	(2.09)

In April 2018, contemporaneous with the closing of our Eagle Ford acquisition, we entered into our Revolving Facility and Term Loan, and used a portion of the proceeds to repay the previous credit facilities. The refinance of the Term Loan was accounted for as a debt modification under ASC 470. As a result, we recognized expense of $0.9 million for third party legal fees. The remaining fees paid of $15.8 million were deferred and are being amortized over the life of the Term Loan.

We(1) ~~recognized~~Lease aoperating ~~loss~~expense ~~on our interest rate swap of $4.3 million~~ and ~~$2.4~~workover ~~million~~expense ~~for the years ended December 31, 2019 and 2018, respectively. Our interest rate swaps~~ are ~~marked~~included totogether ~~market at the end of each reporting period, with the changes~~ in ~~fair~~lease ~~value~~operating being recognized as interest expense. Cash settlements paid to or received by our counterparty are also recorded as interest expense. In 2019, the loss on the interest rate swap consisted of $3.6 million of unrealized losses and ~~$0.6~~workover ~~million~~expenses ~~of realized cash settlements. In 2018, the loss~~ on the ~~interest~~consolidated ~~rate~~statement ~~swap consisted~~ of $2operations.~~1 million of unrealized losses and $0.3 million of realized cash settlements.~~

~~Gain~~(2) onExcludes ~~foreign~~depreciation currency derivative financial instruments. We did not have any foreign currency derivatives in place during the year ended December 31, 2019. During the year ended December 31, 2018, we realized a gain of $6.8 million related to ~~derivative~~corporate ~~contracts put into place to protect the capital commitments made by investors as part of our 2018 equity raise~~assets. At the time of the equity raise, our shares were traded on the ASX, and the derivative instruments provided protection from changes in the AUD to USD exchange rate during the period from launch of equity raise to receipt of funds.

~~Table~~Lease operating expense. Our LOE decreased by $5.8 million (21%) to $22.5 million for the year ended December 31, 2020 from $28.3 million in the prior year, but increased $0.95 per Boe to $6.80 per Boe from $5.85 per Boe. In March 2020, we made field operating changes and renegotiated pricing with a number of ~~Contents~~ our vendors due to the material drop in market oil prices, which reduced our costs on an absolute basis. However, a significant portion of our costs are fixed, and the per Boe rate was negatively impacted by our lower production volumes.

~~Income Tax Expense (Benefit). The components of our provision for income tax expense (benefit) and our effective income tax rates were as follows (in thousands):~~

	Year ended December 31,
Income tax expense (benefit)	2019	2018	Change in $
Current tax expense	—	2,301	(2,301)
Deferred tax expense/(benefit)	(4,518)	11,656	(16,174)
Total income tax (benefit) expense	(4,518)	13,957	(18,475)
Effective tax rate	10.2%	-155.5%

Workover expense. Our workover expenses decreased $2.7 million to $2.7 million for the year ended December 31, 2020, as compared to $5.4 million for the year ended December 31, 2019. Workover expense per Boe decreased $0.29 per Boe to $0.82 per Boe for the year ended December 31, 2020 as compared to the prior year. We have reduced workover expense through conversion of rod pumps to gas lift and redesign of certain rod pump wells to reduce our well failure rates and the associated workover expense going forward. In addition, as a result of the material drop in oil prices, beginning April 2020 through July 2020, we deferred workovers for low producing wells as it was not economic to service the wells which drove down absolute and per Boe workover expense for the year ended December 31, 2020.

~~Our~~Gathering, ~~effective~~processing ~~income~~and ~~tax~~transportation ~~rate~~expense (“GP&T”). GP&T increased by $3.3 million ($2.62 per Boe) to $20.3 million ($6.15 per Boe) for the year ended December 31, 2020 as ~~shown~~compared ~~above~~to $17.1 million ($3.53 per Boe) for the year ended December 31, ~~differs~~2019. GP&T fees are primarily incurred on production from the ~~statutory~~properties ~~rate~~we ~~(21%)~~acquired ~~primarily~~in ~~due~~April to2018. Approximately ~~our~~$12.4 ~~valuation~~million ~~allowance~~and $14. ~~See~~7 ~~Note~~million 9of the GP&T expense was incurred in normal course under various midstream agreements for the years ended December 31, 2020 and 2019, respectively, and the remainder of the expense was related to MRC shortfalls, as discussed below. Sales volumes from the ~~consolidate~~acquired ~~financial~~assets ~~statements~~subject ~~for~~to ~~more~~these ~~information~~midstream agreements decreased 20% in 2020 as compared to 2019.

Other income (expense). During the year ended December 31, 2019, other income (expense) was primarily comprised of expense of $0.7 million for a litigation settlement related to a historical sale of non-operated North Dakota properties in 2013 and expense of $0.9 million for early termination of our drilling rig. Other income (expense) was not material for the year ended December 31, 2018.

~~Adjusted~~Certain ~~EBITDAX.~~of ~~Management~~our ~~has~~midstream ~~historically~~agreements ~~used~~contain ~~both~~MRCs ~~GAAP~~related to fees due on oil, natural gas and ~~certain~~NGL ~~non-GAAP~~volumes ~~measures~~gathered, processed and/or transported. Under the terms of the contracts, if we fail to ~~assess~~pay ~~our~~fees ~~performance. Adjusted~~equal ~~EBITDAX~~to isor greater than the MRC under any of the contracts, we are required to pay a ~~supplemental~~deficiency ~~non-GAAP~~payment ~~financial~~equal ~~measure~~to ~~that~~the isshortfall. Our ~~used~~MRC bycommitment ~~our~~totaled ~~management~~$21.8 million and ~~certain~~$15.8 ~~external~~million ~~users~~for ofthe ~~our~~years ~~consolidated~~ended ~~financial~~December ~~statements~~31, ~~such~~2020 asand ~~investors~~2019, ~~industry~~respectively. The ~~analysts~~shortfall totaled $8.0 million ($2.42 per Boe) and ~~lenders~~$2.3 million ($0.49 per Boe) for the years ended December 31, 2020 and 2019, respectively. The increase in the shortfall year over year was the result of the lower production volumes due largely to the scaled-back development program.

We define “Adjusted EBITDAX” as earnings before interest expense, income taxes, DD&A, property impairments, gain/(loss) on sale of non-current assets, exploration expense, stock-based compensation, gains and losses on commodity hedging, net of settlements of commodity hedging and certain other non-cash or non-recurring income/expense items. 50

~~Our~~Table management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance, identify operating trends (which may otherwise be masked by the excluded items) and compare the results of our operations from period to period without regard to our financing policies and capital structure. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP, or as an indicator of our operating performance or liquidity. Contents

	Year Ended December 31,
Reconciliation of Net Loss to Adjusted EBITDAX (in thousands)	2019		2018
Net loss	$	(39,590)	$	(22,933)
Add back:
Current and deferred income tax expense (benefit)		(4,518)		13,957
Interest expense		38,058		28,631
(Gain) loss on commodity derivative financial instruments, net		20,542		(40,216)
Settlement of commodity derivatives financial instruments		11,094		(599)
Depreciation, depletion and amortization expense		92,334		62,814
Impairment expense		9,990		43,828
Exploration expense		337		3,339
Noncash stock-based compensation expense		504		515
Transaction-related expenses included in general and administrative expenses		2,677		12,396
Gain on foreign currency derivatives		-		(6,838)
Minimum revenue commitment deficiency fees (1)		-		2,757
Other expense (income), net (2)		769		(237)
Adjusted EBITDAX	$	132,197	$	97,414

Production taxes. Our production taxes decreased by $6.0 million (53%) to $5.4 million for the year ended December 31, 2020 from $11.5 million for the prior year, which was driven by our overall decrease in revenue. Production taxes were 5.9% and 5.6% of total revenue for the year ended December 31, 2020 and 2019. During 2020, we recorded a severance tax refund related to prior periods of $1.1 million that the Company expects to receive in 2021. This was offset by higher ad valorem taxes. Ad valorem tax assessments are calculated by the taxing authorities using January 1 commodity pricing. The significant decline in pricing from the beginning of 2020, resulted in the ad valorem as a percentage of revenue for 2020 being higher than the statutory rates applied in the assessment of taxable value at the beginning of the year.

~~Table~~Depletion, depreciation and amortization expense (“DD&A”). Our DD&A expense related to proved oil and natural gas properties decreased by $12.9 million (14%) to $78.8 million for the year ended December 31, 2020 from $91.7 million for the prior year. On a per Boe basis, DD&A increased to $23.83 per Boe for the year ended December 31, 2020 compared to $18.96 per Boe in 2019 primarily due to downward revisions to our proved developed reserves as a result of ~~Contents~~ lower pricing and lower proved undeveloped reserves resulting from changes to our development program. This was partially offset by lower fourth quarter of 2020 DD&A due to the significant impairment in the third quarter 2020, which reduced the carrying value of proved oil and gas properties.

(1) Management has excluded the MRC shortfall incurred in 2018 from Adjusted EBITDAX. The MRC is calculated on a calendar year basis, however, we did not operate the related assets until the 2018 Eagle Ford acquisition closed on April 23, 2019. Due to the timing of the closing, our development plan was back-loaded into 2018, and we were unable to meet the MRC under the midstream agreements.

~~(2)~~Impairment Inexpense. We recorded impairment expense of $331.9 million and $10.0 million for the years ended December 31, 2020 and 2019, ~~other~~In ~~items~~the third quarter of ~~expense~~2020, ~~net,~~we ~~was~~identified ~~primarily~~an ~~related~~impairment triggering event for our proved oil and gas properties due to ~~litigation~~the ~~settlement~~adverse ~~expense~~change ofto ~~$0.8~~our ~~million~~business climate resulting from oil and gas prices declining in 2020 and the resulting changes in our future development plan. InAs ~~2018~~such, ~~other~~we ~~items~~performed a quantitative assessment as of ~~expense~~September 30, ~~net~~2020, ~~included~~and ~~litigation~~the ~~settlements~~estimated undiscounted cash flows from our proved properties were less than the carrying value of ~~$(0.1)~~our ~~million~~oil and ~~other~~gas ~~non~~properties, ~~cash~~which ~~gains~~required ofus ~~$0.3~~to ~~million~~record an impairment.

~~Liquidity and Capital Resources~~

~~Our~~During ~~primary~~the ~~sources~~year ofended ~~liquidity~~December ~~to date have been borrowings under our credit facilities~~31, ~~cash flow from operations~~2019, ~~and strategic dispositions of non-core oil and gas properties. From time to time~~ we ~~have~~recorded ~~also~~impairment ~~raised~~expense ~~additional~~of ~~equity from investors~~$10. ~~Our~~0 ~~primary~~million ~~use~~related ofto ~~capital~~our ~~has~~Dimmit ~~been~~County ~~for the acquisition and development of~~ oil and ~~natural~~ gas properties., ~~Our~~which ~~future~~were ~~ability~~divested toin ~~grow~~October ~~our reserves and production will be highly dependent on the capital resources available to us~~2019.

We and our wholly owned subsidiary, SEI, are parties to the syndicated $250.0 million Term Loan with Morgan Stanley Capital Administrators Inc., as administrative agent, and the Revolving Facility, which is a syndicated reserve-based revolver with Toronto Dominion (Texas) LLC, as administrative agent. The Revolving Facility has a borrowing base of $210.0 million (with a $190 million elected commitment), of which $115.0 million was outstanding as of December 31, 2019. As of the date of this annual report, $58.6 million was undrawn (net of $16.4 million of outstanding letters of credit), although we are currently restricted from making any new draws under the Revolving Facility until completion of the borrowing base redetermination to be completed in the second quarter of 2020. The Revolving Facility matures October 23, 2022, and the Term Loan matures on April 23, 2023. Our Term Loan and Revolving Facility require us to maintain a variety of financial ratios. Of the financial ratio requirements under our credit facilities, our business is generally most sensitive to the Current Ratio. At times, it may be necessary to slow our development pace in order to maintain the required ratio. In addition, as a result of the recent sharp decrease in oil prices, our business is sensitive to the Asset Coverage ratio, particularly in the near-term. See “Credit Facilities” below for a description of the material terms of our credit facilities, financial ratio requirements, and our compliance with these requirements.

AtGeneral & Administrative expense (“G&A”). G&A decreased by $0.1 million (1%) to $22.1 million for the year ended December 31, ~~2019,~~2020 ~~our~~as ~~cash~~compared ~~balance~~to ~~totaled~~ $1222.43 million ~~and~~for the prior year. During the year ended December 31, 2020 we ~~had~~incurred alegal ~~working~~and ~~capital~~advisory ~~deficit~~fees of $347.07 million ($2. ~~Due~~32 per Boe) related to credit facility amendments and debt restructuring described previously, and $0.5 million ($0.14 per Boe) of restructuring costs associated with our workforce reduction in the ~~amounts~~second ~~that~~quarter. During 2019, we ~~incur~~incurred ~~related~~one-time tocosts, ~~our~~primarily ~~drilling~~legal and ~~completion~~accounting ~~program~~fees, ~~and~~to complete our redomiciliation to the ~~timing~~U.S of ~~such~~$2.7 ~~expenditures~~million ($0.55 per Boe). G&A, weexcluding ~~may~~the ~~continue~~costs associated with these discrete transactions, decreased on an absolute basis as compared to ~~incur~~prior ~~working~~year ~~capital~~primarily ~~deficits~~due atto ~~times~~lower insalaries and wages as a result of the ~~future~~expected PPP loan forgiveness of $1.9 million and our workforce and salary reductions.

As a result of the decline in commodity prices since December 31, 2019, we expect our 2020 capital program to be in the range of $40 - $45 million. However, we plan to respond flexibly to market conditions to protect our balance sheet and retain liquidity. We believe that our cash flow generated from operating activities (which includes proceeds from settlements of hedging contracts) and cash on hand at December 31, 2019 will be sufficient to execute this plan.

~~Our~~As ~~liquidity~~described isunder Credit ~~highly~~Facilities, ~~dependent~~our onG&A ~~prices we receive~~ for the ~~sale~~second ~~of oil, gas,~~ and ~~NGLs~~third wequarter ~~produce. Prices~~of ~~we receive are determined by prevailing market conditions and greatly influence our revenue~~2020, ~~cash~~was ~~flow,~~limited ~~profitability, ability~~ to ~~comply~~$3 ~~with~~million ~~financial~~per quarter and ~~other~~the ~~covenants~~fourth inquarter ~~our~~was ~~credit~~limited ~~facilities, access~~ to ~~capital and future rate of growth~~$3. We6 ~~expect~~million ~~that~~(as indefined ~~the future, our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines~~ in the ~~price of oil and natural gas~~agreements). ~~However,~~ inAfter athe ~~portion~~adjustments ofprovided ~~our~~for ~~current positions, our hedging activity may also reduce our ability to benefit from increases~~ in ~~oil and natural gas prices. We may realize losses to~~ the ~~extent our derivatives contract prices are lower than market prices and~~agreements, ~~conversely,~~ we ~~will~~were ~~realize gains to the extent our derivatives contract prices are higher than market prices. At times, we may choose to liquidate derivative positions before the contract ends~~ in ~~order~~compliance ~~realize~~with the ~~current~~covenant value of our existing positions, to the extent permitted by our credit facilities. Please see Note 10 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report for athese ~~summary of our outstanding derivative positions as of December 31, 2019~~periods.

~~Table of Contents~~ 51

~~Similar~~Table ~~to what we have experienced in previous periods~~ of sustained low commodity prices, the prevailing market price for oil and gas services has also decreased, including the types of costs included in our lease operating expenses, drilling costs, completion costs and costs to equip our wells. Since the sharp decline in oil pricing in March 2020, we have renegotiated pricing with a number of our vendors and we have secured contractual arrangements with drilling and completion service providers at reduced costs relative to those in place during 2019 and the assumed cost structure used in our year-end reserve report. Additionally, we have changed our field operating procedures in response to the material drop in oil prices which further serves to reduce our cost structure relative to that assumed in the Company’s year-end reserve report. We are actively working to secure additional cost savings and if commodity prices remain low for a sustained period of time, we expect further reductions to our costs. Contents

IfGain/loss on commodity ~~prices~~derivative ~~remain~~financial ~~depressed~~instruments. ~~for~~Our ancommodity ~~extended~~derivative ~~period~~contracts ofare ~~time~~marked orto market at the ~~capital/credit~~end ~~markets~~of ~~become~~each ~~constrained,~~reporting period with the ~~borrowing~~changes ~~capacity~~in ~~under~~fair ~~our~~value ~~Revolving~~being ~~Facility~~recognized ~~could~~as begain ~~adversely~~(loss) ~~affected~~on commodity derivative financial instruments, net. Cash Inflow, however, is only impacted by the ~~event~~monthly ofsettlements apaid ~~reduction~~to inor received by the ~~borrowing~~counterparty, ~~base~~which ~~under~~are ~~our~~also ~~Revolving~~recorded ~~Facility,~~as wegain(loss) ~~may~~on becommodity ~~required~~derivative tofinancial ~~prepay~~instruments, ~~some~~net. orThe ~~all~~components of ~~our~~gain ~~indebtedness~~(loss) ~~prior~~on tocommodity ~~maturity,~~derivative ~~which~~financial ~~would~~instruments ~~adversely~~was ~~affect~~as ~~our~~follows ~~capital~~(in ~~expenditure program.~~ thousands):

The amount, timing and allocation of these and other future expenditures is largely discretionary. As a result, the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects and market conditions.

Cash Flows



	Year Ended December 31,
Gain (loss) on commodity derivative financial instruments, net	2020		2019		$ Change
Unrealized gains (losses)	$	1,803	$	(31,637)	$	33,440
Realized gains ⁽¹⁾		50,429		11,095		39,334
Total	$	52,232	$	(20,542)	$	72,774

~~Our cash flows for the years ended December 31, 2019 and 2018 are as follows:~~

	Year ended December 31,
(In $ ’000s)	2019		2018
Net cash provided by operating activities	$	111,229	$	43,814
Net cash used in investing activities	$	(149,989)	$	(386,788)
Net cash provided by financing activities	$	49,581	$	338,817

(1)

The realized gains for the years ended December 31, 2020 and 2019, included proceeds of $7.0 million and $3.6 million from unwinding derivative positions before their contractual maturity.

Cash flows provided by operating activities. Cash provided by operating activities for the year ended December 31, 2019 was $111.2 million, an increase of $67.4 million compared to the prior year ($43.8 million). This increase was primarily due to higher revenues resulting from an increase in production volumes, partially offset by lower pricing. Including the impact of derivative settlements, our realized price per Boe decreased 5% to $44.39 per Boe as compared to $46.84 per Boe. During 2019, we had cash settlements from our derivative contracts of $11.3 million, of which $3.6 million was generated from unwound derivative contracts. Despite our 38% increase in production volumes, we have been able to realize lower LOE and workover and G&A costs on a per Boe basis due to economies of scale and internal cost saving initiatives, which increased our operating margin in 2019.

~~Due~~Interest ~~to payment timing~~expenses, ~~our~~net ~~cash~~of ~~flows~~amounts ~~from~~capitalized. ~~operations~~The ~~for~~components ~~the~~of ~~year ended December 31, 2019 included three quarterly~~ interest ~~payments on our Term Loan~~expense, ~~whereas,~~net ~~the~~of ~~year~~amounts ~~ended~~capitalized ~~December~~was ~~31,~~as ~~2018~~follows ~~included four quarterly interest payments, which resulted~~ (in ~~higher cash flows in 2019 of $6.5 million. During 2018, we paid federal withholding taxes of $2.3 million related to a U.S. tax restructuring for our subsidiaries.~~ thousands):

Cash flows used in investing activities. Cash used in investing activities for the year ended December 31, 2019 decreased to $150.0 million as compared to $386.8 million in prior year. In 2019 net cash flows used in investing activities was primarily for development of proved properties ($166.7 million), partially offset by the sale of our Dimmit County, Texas, oil and gas assets in October 2019 ($17.3 million). We expect to receive the additional proceeds from the sale of $4.2 million in 2020. Net cash used in investing activities in 2018 included $215.8 million for the Company’s Eagle Ford acquisition and $169.0 million for development of our oil and gas properties. See Capital Expenditures below for additional information regarding our investment in oil and gas properties.


	Year ended December 31,
Interest Expense	2020		2019			Change in $	Change as %
Interest expense on Term Loan, Revolving Facility and other	$	31,990	$	32,720	$	(730)	(2)
Amortization of debt issuance costs		3,707		3,351		356	11
Expense incurred with debt modification		1,199		—		1,199	100
Loss on interest rate swap		3,324		4,270		(946)	(22)
Capitalized interest		(711)		(2,283)		1,572	(69)
Total	$	39,509	$	38,058	$	1,451	4

~~Table~~The decrease in interest expense on our Term Loan, Revolving Facility and other for the year ended December 31, 2020 was driven by the decrease in the average market interest rates, partially offset by an increase in the amount of ~~Contents~~ outstanding debt and additional 2% of paid-in-kind (“PIK”) interest, which is added to the principal of the Term Loan. The PIK interest, effective May 30, 2020, was added as part of the third amendment to the Term Loan in June 2020, and totaled $3.0 million for year ended December 31, 2020, respectively. Our weighted average debt outstanding during 2020 was $371 million (excluding the impact of PIK) versus $347 million for 2019. At December 31, 2020, the stated weighted average interest rates on the Revolving Facility and the Term Loan were 7.40% (including default interest of 2%) and 11.00% (including 2% PIK interest added to the principal at each reporting period), respectively, as compared to 4.75% and 10.11%, at December 31, 2019. Default interest of 2% was added to the Term Loan interest rate beginning in January 2021.

Cash flows provided by financing activities. Cash provided by financing activities for the year ended December 31, 2019 decreased to $49.6 million as compared to $338.8 million for the year ended December 31, 2018. During 2019, we borrowed $50.0 million on our Revolving Facility to fund a portion of our 2019 drilling program. In 2018, we raised $250.1 million (net of fees and including the impact of our foreign currency derivatives) in connection with the Eagle Ford acquisition, plus proceeds from borrowings of $315 million as a result of entering into our Term Loan and Revolving Facility. This was partially offset by the repayment of our previous credit facility of $192 million, the repayment of a production advance from our then oil purchaser, of $18.2 million and borrowing costs of $16.0 million.

~~Capital~~As ~~Expenditures~~described in Note 6 to our Conslidated Financial Statements, we entered into the fourth amendment to our Revolving Facility in January 2020, which among other things, appointed Toronto Dominion (Texas) LLC, as the administrative agent (replacing Natixis). As a result of the former administrative agent exiting the facility and terminating its commitments, we wrote-off previously capitalized deferred debt issuance costs of $1.1 million during 2020 in accordance with Accounting Standards Codification 470 - Debt. We capitalized new financing and legal fees of $1.0 million, which will be amortized over the remaining loan term. In June 2020, we entered into the fifth amendment to our Revolving Facility, which among other things, reduced our borrowing base from $210 million to $170 million. As a result, we wrote-off deferred debt issuance costs in proportion to the decrease in borrowing base of $0.1 million.

~~The following table summarizes our capital expenditures incurred (excluding acquisitions and changes related to its asset retirement obligation) for the years ending December 31, 2019 and 2018.~~

	Year ending December 31
(In $ ’000s)	2019		2018		Change in $	Change in %
Unproved (1)	$	177	$	1,609	(1,432)	(89)
Proved (1)		149,766		181,463	(31,697)	(17)
Total	$	149,943	$	183,072	(33,129)	(18)

~~(1)~~Table ~~Capital expenditures for unproved properties includes costs incurred at our Dimmit County properties, which were held for sale and disposed~~ of in October 2019, of nil and $1.0 million during the years ended December 31, 2019 and 2018, respectively. Capital expenditures for proved properties includes costs incurred at the Dimmit County properties of $8.4 million and $5.3 million as of December 31, 2019 and 2018, respectively. We began drilling two wells in late 2018 in Dimmit County to extend the acreage lease term.Contents

~~Our~~We ~~capital~~recognized ~~expenditures~~a ~~for~~loss ~~proved~~on ~~properties~~our interest rate swap of $3.3 million and $4.3 million for the ~~year~~years ended December 31, 2020 and 2019, ~~decreased~~respectively. Our ~~17%~~interest rate swaps are marked to ~~$149.8~~market ~~million,~~at asthe ~~compared~~end toof ~~$181.5~~each ~~million~~reporting inperiod, with the ~~prior~~changes ~~year. Our~~in ~~drilling~~fair ~~and~~value ~~completion~~being ~~costs~~recognized ~~totaled~~as ~~$125~~interest expense.0 Cash ~~million,~~settlements ~~which~~paid ~~included~~to ~~costs~~or toreceived ~~add~~by ~~22.3~~our ~~net~~counterparty ~~producing~~are ~~wells~~also ~~and~~recorded ~~there~~as ~~were~~interest 2expense.0 In ~~additional~~2020, ~~net~~the ~~operated~~loss ~~wells~~on ~~waiting~~the oninterest ~~completion~~rate swap consisted of $5.8 million of unrealized gains and 0$9.31 ~~non~~million ~~operated~~of ~~wells~~realized incash ~~the~~settlements, ~~process~~which included payments to unwind all of ~~being~~the ~~drilled~~outstanding swap positions in December 2020. In ~~addition~~2019, wethe ~~invested~~loss on the interest rate swap consisted of $133.6 million ~~into~~of ~~shared~~unrealized ~~facility~~losses ~~projects~~and ~~during~~$0.6 ~~the~~million ~~year~~of ~~ended~~realized ~~December~~cash ~~31, 2019~~settlements.

~~Credit Facilities~~

WeIncome ~~and~~Tax ~~our wholly owned subsidiary, SEI, are parties to the Term Loan, which is syndicated $250~~Benefit.0 ~~million~~The ~~second~~components lien term loan with Morgan Stanley Capital Administrators Inc., as administrative agent, and the Revolving Facility, which is a syndicated reserve-based revolver with Toronto Dominion (Texas) LLC, as administrative agent, which has a borrowing base of ~~$210.0~~our ~~million,~~provision anfor ~~elected~~income ~~commitment~~tax ofbenefit ~~$190 million,~~ and ~~$115.0 million outstanding as of December 31, 2019. The Revolving Facility matures October 23, 2022, and the Term Loan matures on April 23, 2023. We refer to~~ our ~~Revolving~~effective ~~Facility~~income ~~and~~tax ~~Term~~rates ~~Loan~~were ~~collectively~~ as ~~our~~follows ~~“credit~~(in ~~facilities”.~~ thousands):

Interest on the Revolving Facility accrues at LIBOR plus a margin that ranges from 2.25% to 3.25% based upon the amount drawn. Interest on the Term Loan accrues at LIBOR (with a LIBOR floor of 1.0%) plus 8.0%.


	Year ended December 31,
Income tax benefit	2020		2019		Change in $
Current tax benefit	$	(85)	$	—	$	(85)
Deferred tax benefit		(6,916)		(4,518)		(2,398)
Total income tax benefit	$	(7,001)	$	(4,518)	$	(2,483)
Effective tax rate		1.9%		10.2%

~~Under the Revolving Facility, we are required to maintain the following financial ratios:~~

·Our aeffective ~~minimum~~income ~~Current~~tax ~~Ratio~~rate, ~~consisting~~as ofshown ~~consolidated~~above, ~~current~~differs ~~assets~~from ~~(as defined in~~ the ~~Revolving~~statutory ~~Facility~~rate (21%) ~~including~~primarily ~~undrawn~~due ~~borrowing capacity~~ to ~~consolidated~~our ~~current~~valuation ~~liabilities~~allowance. See ~~(as~~Note ~~defined~~8 inPart ~~the Revolving Facility)~~II, ofItem ~~not less than 1~~8.0 to“Financial ~~1.0~~Statements asand ofSupplementary Data”to the ~~last~~consolidate ~~day~~financial ofstatements ~~any~~for ~~fiscal~~more ~~quarter;~~information.

·Other aincome ~~maximum~~(expense). ~~Leverage~~During ~~Ratio~~the year ended December 31, ~~consisting~~2020, ofwe ~~consolidated~~conveyed ~~Total~~our ~~Debt~~non-core tointerest ~~adjusted~~in ~~consolidated~~the ~~EBITDAX~~petroleum ~~(as~~exploration ~~defined~~license 570 located in the ~~Revolving~~Cooper ~~Facility~~Basin in Australia (“PEL570”), to the property’s operator. At the time of ~~not~~the ~~greater~~conveyance, ~~than~~we ~~3.5~~had accrued expenses related to 1exploratory drilling of approximately $3.7 million. As consideration for the property, the operator settled our outstanding liability for $0.9 asmillion. The property had previously been fully impaired, and therefore we recognized a gain on the conveyance of $2.7 million. As a result of the ~~last~~conveyance, ~~day~~we were also relieved of our commitment to fund any ~~fiscal~~further ~~quarter;~~exploratory drilling for PEL570. In 2019 other income (expense) was primarily comprised of expense of $0.7 million for a litigation settlement related to a historical sale of non-operated North Dakota properties in 2013 and expense of $0.9 million for early termination of our drilling rig.

· a minimum Interest Coverage Ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Revolving Facility), of not less than 1.5 to 1.0 as of the last day of any fiscal quarter (for such time as there a similar covenant under ours or SEI’s subordinated indebtedness).

50 Adjusted EBITDAX. Management has historically used both GAAP and certain non-GAAP measures to assess our performance. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by our management and certain external users of our consolidated financial statements, such as investors, industry analysts and lenders.

~~Table of Contents~~

~~Under~~We ~~the~~define ~~Term~~“Adjusted ~~Loan~~EBITDAX” as earnings before interest expense, weincome ~~are~~taxes, ~~required~~DD&A, toproperty ~~maintain~~impairments, ~~the~~gain/(loss) ~~following~~on ~~financial~~sale ~~ratios:~~ of non-current assets, exploration expense, stock-based compensation, gains and losses on commodity hedging, net of settlements of commodity hedging and certain other non-cash or non-recurring income/expense items.

· a minimum Interest Coverage Ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Term Loan), of not less than 1.5 to 1.0 as of the last day of any fiscal quarter (for such time as there a similar covenant under ours or SEI’s subordinated indebtedness); and

·Our anmanagement ~~Asset~~believes ~~Coverage~~Adjusted ~~Ratio,~~EBITDAX ~~consisting~~is ofuseful ~~Total~~because ~~Proved~~it ~~PV9%~~allows us to ~~Total~~more ~~Debt~~effectively evaluate our operating performance, identify operating trends (aswhich ~~defined~~may inotherwise ~~the~~be ~~Term~~masked ~~Loan~~by ~~agreement~~the excluded items), and compare the results of ~~not~~our ~~less~~operations ~~than~~from 1period to period without regard to our financing policies and capital structure.50 Adjusted EBITDAX should not be considered as an alternative to, 1or more meaningful than, net income as determined in accordance with GAAP, or as an indicator of our operating performance or liquidity.0.

The Revolving Facility agreement requires us to hedge at least 50% of reasonably projected oil and gas production from the Proved Reserves classified as “Developed Producing Reserves” for a rolling 36 month period, but not more than 85% of reasonably projected production from the Proved Reserves for a rolling 24 months and not more than 75% of the reasonably projected production from the Proved reserves for months 25-60. 53

~~EBITDAX,~~Table ~~as defined in the Term Loan and the Revolving Facility, is calculated as consolidated net income (loss) less the impact~~ of interest, income taxes, depreciation, depletion, amortization, exploration expenses and other non-cash charges and income (including stock-based compensation, and unrealized gains and loss on derivative instruments). In addition, our Credit Agreements contain various covenants that limit our ability to take certain actions, including, but not limited to, the following: Contents

· incur indebtedness or grant liens on any of our assets;


	Year Ended December 31,
Reconciliation of Net Loss to Adjusted EBITDAX	2020		2019
Net loss	$	(370,462)	$	(39,590)
Add back:
Current and deferred income tax benefit		(7,001)		(4,518)
Interest expense		39,509		38,058
(Gain) loss on commodity derivative financial instruments, net		(52,232)		20,542
Settlement of commodity derivatives financial instruments		50,428		11,094
DD&A		79,582		92,334
Impairment expense		331,877		9,990
Exploration expense		193		337
Noncash stock-based compensation expense		280		504
Transaction-related expenses included in G&A expense (1)		7,852		2,677
Reduction-in-force related expenses included in G&A expense		476		—
Other expense (income), net (2)		(2,739)		769
Adjusted EBITDAX	$	77,763	$	132,197

~~· enter into certain commodity hedging agreements;~~

·(1) ~~sell~~In 2019 and early 2020, ~~transfer~~we incurred one-time costs, ~~assign~~primarily orlegal ~~convey~~and ~~assets~~accounting fees, ~~including~~to acomplete ~~sale~~our ofRedomiciliation ~~all~~to orU.S. ~~substantially~~Additionally, ~~all~~in of2020, we incurred costs to amend our ~~assets~~credit facilities, orexplore ~~engage~~transactions into ~~certain~~reduce ~~mergers~~our orleverage ~~acquisitions;~~(as required by the third, fourth and fifth amendments to the Term Loan) and complete the RSA.

·(2) ~~make~~In ~~certain~~2020, ~~distributions~~other expense (~~including~~income), ~~payments~~net included a $2.7 million gain on the conveyance of ~~dividends);~~PEL570 to the operator. In 2019, other items of expense, net was primarily related to litigation settlement expense of $0.8 million.

~~· make certain loans, advances and investments; and~~

·Liquidity ~~engage~~and inCapital ~~transactions with affiliates.~~Resources

If an event of default exists under either the Revolving Facility or the Term Loan, the administrative agents will be able to terminate the commitments under the credit facilities and accelerate the maturity of all loans made pursuant to our credit facilities and exercise other rights and remedies. Events of default include, but are not limited to, the following events:

~~· failure to pay any principal when due under the Revolving Facility or Term Loan;~~Overview

~~· failure to pay any other obligation when due and payable within three business days after same becomes due~~

·On ~~failure~~December to31, ~~observe or perform any covenant~~2020, ~~condition~~our orcash ~~agreement~~balance intotaled ~~the~~$5.3 ~~Revolving~~million ~~Facility~~and orwe ~~Term~~had ~~Loan~~a orworking ~~other~~capital ~~loan~~deficit ~~documents,~~of ~~subject,~~$21.5 inmillion ~~certain~~(exclusive ~~instances,~~of tothe ~~certain~~current ~~cure~~classification ~~periods;~~of debt).

~~· failure of any representation and warranty made in connection with the loan documents to be true and correct in all material respects;~~

·Our ~~bankruptcy~~liquidity oris ~~insolvency~~highly ~~events~~dependent ~~involving~~on prices we receive for the sale of oil, gas, and NGLs we produce. Prices we receive are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, ability to comply with financial and other covenants in our credit facilities, access to capital and future rate of growth. We maintain a portfolio of derivative positions to help us orstabilize a portion of our ~~subsidiaries;~~expected cash flows from operations despite potential declines in the price of oil and natural gas. At times, we may choose to liquidate derivative positions before the contract ends in order realize the current value of our existing positions, to the extent permitted by our credit facilities. As of the date of this report, we had had oil derivatives in place covering an average of 3,142 Bbls per day for remainder of 2021 at a weighted average floor price of $48.16. Please see Note 9 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report for a summary of our outstanding derivative positions as of December 31, 2020.

~~· cross-default to other indebtedness in excess of $5 million;~~

·Chapter ~~certain~~11 ~~ERISA~~Cases ~~events~~and ~~involving~~Effect usof orAutomatic ~~our subsidiaries;~~Stay

~~· a violation of the terms of the Intercreditor Agreement; and~~

·On March 9, 2021, we field for relief under Chapter 11 of the Bankruptcy Code. The commencement of a ~~change~~voluntary proceeding in bankruptcy constituted an immediate event of ~~control~~default ~~(as~~under ~~defined~~our Revolving Facility and Term Loan, resulting in the automatic and immediate acceleration of all of our ~~credit~~debt ~~facilities)~~outstanding. Any efforts to enforce payment obligations related to the acceleration of our debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Also on March 9, 2021, we entered into a RSA with the Revolving Facility and Term Loan lenders to support a reorganization in accordance with the term set forth therein. As more fully described in Note 15 Subsequent Events, the Plan and the RSA contemplate a reorganization which would provide for the treatment of holders of certain claims and existing equity interests.

We and SEI and their respective subsidiaries have also executed and delivered certain other related agreements and documents pursuant to the credit facilities, including a guarantee and collateral agreement and mortgages for both the Revolving Facility and the Term Loan. Our obligations as well as those of SEI and SEI’s respective subsidiaries under the Revolving Facility are secured by a first priority security interest in favor of the lenders, in our, SEI’s and SEI’s respective subsidiaries’ tangible and intangible assets, and proved reserves, among other things. Our obligations as well as those of SEI and SEI’s respective subsidiaries under the Term Loan are secured by a second priority security interest in favor of the lenders, in our, SEI’s and SEI’s respective subsidiaries’ tangible and intangible assets, and proved reserves, among other things. 54

51 Table of Contents

~~Table~~We expect to continue operations in the normal course for the duration of ~~Contents~~ the Chapter 11 Cases. To ensure ordinary course operations, we have obtained approval from the Bankruptcy Court for certain “first day” motions to continue our ordinary course operations after the filing date. In addition, we have obtained a new up to $50 million DIP Facility to fund operations during bankruptcy proceedings. For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to a high degree of risk and uncertainty associated with our Chapter 11 Cases. The outcome of the Chapter 11 Cases is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court and our Lenders. The significant risks and uncertainties related to our liquidity and Chapter 11 Cases described above raise substantial doubt about our ability to continue as a going concern. There can be no assurance that we will confirm and consummate the Plan as contemplated by the RSA or complete another plan of reorganization with respect to the Chapter 11 Cases. As a result, we have concluded that our plans do not alleviate substantial doubt about our ability to continue as a going concern.

A breach of any covenant, including the Asset Coverage Ratio, in our credit agreements will result in default under both our Term Loan and cross default on our Revolving Credit Facility, after any applicable grace period. A default, if not waived, could result in acceleration of the amounts outstanding under the credit facilities. In the event that some or all of the amounts outstanding under our credit facilities are accelerated and become immediately due and payable, we may not have the funds to repay, or the ability to refinance, such outstanding amounts and our lenders could foreclose upon our assets. If we are unable to remain in compliance with our financial and non-financial covenants, we intend to seek a waiver or covenant relief. However, no assurances can be given that we will be able to obtain such relief.

AsSources of ~~December~~Liquidity ~~31, 2019, we were in compliance with all the covenants in our Revolving Facility~~ and ~~Term~~Capital Loan. As described above, we are required to maintain an Asset Coverage Ratio of not less than 1.5 to 1.0, which is calculated as the value of our Total Proved Reserves (PV 9%) using Nymex pricing and giving consideration to the value of our commodity derivative instruments, to Total Debt. The value of our oil and gas reserves, (including “Total Proved Reserves” as described in the Term Loan agreement) is highly sensitive to future commodity prices, and as a result of the decline in prices since year-end, there is uncertainty regarding our ability to maintain the covenant through the 12 months following the date of this report. We regularly enter into commodity derivative contracts to protect the cash flows associated with our proved developed producing wells and to provide supplemental liquidity to mitigate decreases in revenue due to reductions in commodity prices. As described above, we believe, based on historical experience, that the prevailing market price for oil and gas services also decreases during periods of sustained low commodity prices, and we have secured numerous cost reductions to date in 2020. Resources

Despite the risks and uncertainties described above, we believe we have or likely will be able to implement plans to substantially mitigate any potential breach of covenant related to this pricing downturn. However, since we cannot guarantee our ability to maintain compliance with the Asset Coverage Ratio and other covenants and cannot guarantee that we will be able to obtain waivers if a covenant is breached, it raises uncertainty about our ability to continue as a going concern.

~~As described above~~Historically, ~~the~~our ~~Revolving~~primary ~~Facility~~sources ~~and Term Loan each contain reporting covenants that require delivery~~ of ~~audited~~liquidity ~~consolidated~~have ~~financial~~been ~~statements~~borrowings ~~and~~under ~~related~~our ~~reports~~credit ~~and~~facilities, ~~certificates~~cash onflow orfrom ~~before certain deadlines~~operations, ~~provided~~ ~~for~~and instrategic ~~each~~dispositions of ~~the~~non-core ~~Revolving~~oil ~~Facility~~ and ~~Term~~gas ~~Loan Facility~~properties. ~~Additionally,~~ From ~~our~~time ~~financial~~to ~~statements~~time, ~~must~~we behave ~~delivered~~also ~~without~~raised aadditional ~~going~~equity ~~concern~~from ~~or like qualification or exception~~investors. ~~Failure~~ Our toprimary ~~comply~~use ~~with~~of ~~these~~capital ~~covenants~~has ~~would~~been ~~constitute~~for ~~a default under both~~ the ~~Revolving~~acquisition ~~Facility~~ and ~~Term~~development ~~Loan. The report~~ of ~~the~~oil ~~Company’s~~and ~~independent~~natural ~~registered~~gas ~~public~~properties. ~~accounting~~At ~~firm~~December ~~that~~31, ~~accompanies~~2020, ~~our~~we ~~audited~~had ~~consolidated~~outstanding ~~financial~~borrowings ~~statements~~on inour ~~this~~Term ~~annual~~Loan ~~report~~of ~~contains~~$253.0 anmillion ~~explanatory~~(including ~~paragraph~~PIK) ~~regarding~~and ~~the~~$130.6 ~~substantial~~million ~~doubt~~on ~~about~~ the ~~Company’s~~Revolving ~~ability to continue as a going concern~~Facility. To We ~~address~~were ~~this,~~not ~~and~~in ~~any~~compliance ~~potential~~with ~~default~~certain ~~arising~~of ~~from~~the acovenants ~~failure~~of tothe ~~deliver~~Term ~~consolidated~~Loan ~~audited financial statements~~ and ~~related~~Revolving ~~reports~~Facility ~~and~~our ~~certificates~~credit byfacilities ~~the~~at ~~applicable~~December ~~deadlines~~31, we2020. As ~~have~~described ~~entered~~above, ~~into~~the ~~waivers~~commencement ~~with~~of ~~our lenders under~~ the ~~Revolving~~Chapter ~~Facility~~11 ~~and~~Cases ~~Term~~subsequent ~~Loan. These~~to ~~waivers were effective as of April 29~~yearend, ~~2020,~~resulted ~~subject~~in toan ~~the~~automatic ~~conditions~~and ~~set~~immediate ~~forth~~acceleration inof ~~the~~all ~~waivers, which included delivery~~ of our ~~audited~~debt ~~consolidated~~outstanding. We ~~financial~~also ~~statements~~have ~~for~~other ~~the~~contractual ~~fiscal~~commitments, ~~year~~which ~~ended~~are ~~December~~described ~~31,~~in Note ~~2019~~14—Commitments and ~~related~~Contingencies in ~~reports~~Part ~~and certificates~~II, ~~and~~Item ~~payment~~8 ofFinancial ~~the fees and expenses of the administrative agent incurred in connection with such waivers~~ Statements.

In consideration for the waiver under our Revolving Facility, we agreed to certain limitations on our ability to effect draws under the Revolving Facility until such time as the May 2020 borrowing base redetermination has been completed. In addition, in consideration for the waiver with respect to the Term Loan, we agreed to amend certain covenants in the Term Loan, as to be mutually agreed with the Term Loan lenders within 15 days. The waiver under our Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion. Failure to enter into such amendment with respect to our Term Loan within 15 days (or a similar amendment with respect to our Revolving Facility on the date the Term Loan is amended) would constitute an event of default under our credit facilities, in which case the amounts outstanding under our credit facilities could be accelerated and become immediately due and payable. While we believe that we will finalize such amendments within the required time frame, there can be no assurance that our efforts will result in any finalizing these amendments or the ultimate terms of any such amendments.

52 With cash on hand and cash flow from operations combined with the up to $50 million DIP Facility, we expect to have sufficient liquidity to fund anticipated cash requirements through the Chapter 11 Cases.

~~Table of Contents~~

~~With~~Cash ~~respect~~Flows to the Term Loan, we have engaged in preliminary discussions regarding the terms of the required amendment. In addition, we and have agreed to explore in good faith with our Term Loan Lenders options to reduce our overall level of indebtedness and leverage and limit capital and general and administrative expenditures for some specified period of time. As described above, the lenders under our Revolving Facility may request corresponding amendments under the Revolving Facility.

~~Off-Balance Sheet Arrangements~~

WeOur docash ~~not~~flows ~~have~~for ~~any~~the years ~~off-balance~~ended ~~sheet~~December 31, ~~arrangements~~2020 ~~that~~and ~~have,~~2019 or are ~~reasonably~~as ~~likely~~follows: ~~to have, a current or future effect on our financial statements, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.~~

Critical Accounting Policies and Estimates


	Year ended December 31,
(In $ ’000s)	2020		2019
Net cash provided by operating activities	$	33,051	$	111,229
Net cash used in investing activities	$	(54,461)	$	(149,989)
Net cash provided by financing activities	$	14,277	$	49,581

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in our financial statements. Actual results could differ from our estimates and assumptions, and these differences could result in material changes to our financial statements. The following discussion presents information about our most critical accounting policies and estimates. Our significant accounting policies are further described in Note 1 to our audited consolidated financial statements included in “Item 8. Financial Statements and Supplemental Data” of this annual report.

~~Estimates~~Cash offlows ~~Oil~~provided ~~and~~by ~~Gas~~operating ~~Reserve Quantities~~activities. ~~The~~Cash ~~estimated~~provided ~~quantities~~by ofoperating ~~oil,~~activities ~~natural~~for ~~gas~~the ~~and~~year ~~NGL~~ended ~~reserves~~December ~~are~~31, ~~integral~~2020 towas ~~the~~$33.1 ~~calculation~~million, a decrease of ~~DD&A~~$78.2 ~~and~~million compared to ~~assessments~~the ofprior ~~possible~~year ~~impairment~~($111.2 ~~of assets~~million). ~~Proved~~Including ~~oil~~the ~~and~~effect ~~gas~~of ~~reserves~~derivative ~~are~~settlements, ~~those~~including ~~quantities~~unwound ofpositions, ~~oil~~(as ~~and~~shown ~~gas~~on ~~which~~page 50), byour ~~analysis~~realized ofprice ~~geoscience~~per ~~and~~Boe ~~engineering~~decreased ~~data,~~3% ~~can~~to be$43.02 ~~estimated~~per ~~with~~Boe ~~reasonable~~as ~~certainty~~compared to be$44.39 ~~economically~~per ~~producible—from~~Boe. aDuring ~~given date forward~~2020, ~~from~~we ~~known~~had ~~reservoirs~~cash ~~and~~settlements ~~under~~from ~~existing~~our ~~economic~~derivative ~~conditions,~~contracts ~~operating~~of ~~methods,~~$49.84 ~~and government regulations~~million. ~~These~~ Despite ~~estimates~~the ~~require~~relatively ~~significant~~small ~~judgements~~decrease toin berealized ~~made~~price, ~~regarding~~our ~~future~~sales ~~development~~volume ~~and~~decreased ~~production~~by ~~costs~~32%, ~~development~~resulting ~~plans~~in ~~and~~a ~~fiscal~~significant ~~regimes.~~decrease ~~The~~in ~~estimates~~operating ofcash ~~reserves~~flow. In ~~may~~addition, ~~change~~we ~~from~~had ~~period~~higher tocash ~~period~~flows asfor ~~the~~G&A ~~economic~~expenses ~~assumptions~~due ~~used~~to costs incurred to ~~estimate~~restructure ~~the~~our ~~reserves~~debt. This ~~can~~was ~~change~~partially ~~from~~offset ~~period~~by tothe ~~period~~receipt ~~and~~of as$1.9 ~~additional~~million ~~geological~~of ~~data~~PPP isproceeds, ~~generated~~which ~~during~~we ~~the~~expect ~~course~~to ofbe ~~operations~~forgiven. Due ~~Ryder~~to ~~Scott~~payment ~~prepared~~timing, ~~100%~~our ofcash ~~our~~flows ~~proved~~from ~~reserve~~operations ~~estimates~~for asthe ofyear ended December 31, 2019 ~~and~~included ~~2018.~~three Inquarterly ~~connection~~interest ~~with~~payments ~~Ryder~~on ~~Scott~~our ~~performing~~Term ~~their~~Loan, ~~independent reserve~~whereas ~~estimations,~~the weyear ~~furnish~~ended ~~them~~December ~~with~~31, ~~the~~2020 ~~following~~included ~~information~~four ~~that~~quarterly ~~they~~interest ~~review:~~payments, ~~(i)~~which ~~technical~~resulted ~~support~~in ~~data,~~higher ~~(ii)~~cash ~~technical~~flows ~~analysis~~in 2019 of ~~geologic~~$6.5 ~~and~~million. In ~~engineering support information~~addition, ~~(iii)~~we ~~economic~~paid ~~and~~$6.3 ~~production~~million ~~data~~to ~~and~~unwind ~~(iv)~~ our ~~well~~interest ~~ownership~~rate ~~interests~~swaps ~~and~~in ~~(v)~~December ~~expected future development plans~~2020.

Depreciation, Depletion and Amortization. The quantities of estimated proved oil and gas reserves are a significant component of our calculation of DD&A expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserve quantities were revised upward or downward, net income would increase or decrease, respectively.

~~DD&A~~Cash offlows ~~the~~used ~~cost~~in ofinvesting ~~proved~~activities. ~~oil~~Cash ~~and~~used ~~gas~~in ~~properties~~investing isactivities ~~calculated~~for ~~using~~ the ~~unit-of-production~~year ~~method. The~~ended ~~reserve~~December ~~base~~31, ~~used~~2020 decreased to ~~calculate~~$54.5 ~~depreciation,~~million ~~depletion~~as ~~and~~compared ~~amortization~~to ~~for~~$150.0 ~~proved~~million ~~leasehold~~in ~~acquisition~~prior ~~costs~~year. isIn ~~the~~2020 ~~sum~~and of2019, ~~proved~~net ~~developed~~cash ~~reserves~~flows ~~and~~used ~~proved~~in ~~undeveloped~~investing ~~reserves. With~~activities ~~respect~~was toprimarily ~~lease~~for ~~and~~development ~~well~~of ~~equipment~~proved ~~costs,~~properties ~~which~~($54.2 ~~include~~million ~~development costs~~ and ~~successful~~$166.7 ~~exploration~~million, ~~drilling~~respectively). In ~~costs~~2019, ~~the~~this ~~reserve~~was ~~base~~partially ~~includes~~offset ~~only~~by ~~proved~~the ~~developed~~sale ~~reserves. We~~of ~~have~~our ~~one~~Dimmit ~~unit-of-production~~County, ~~field~~Texas, ~~the~~oil ~~Eagle~~and ~~Ford~~gas ~~formation.~~assets ~~This~~in ~~method~~October ~~considers~~2019 ~~the~~($17.3 ~~geographic~~million). See ~~concentration,~~Capital ~~operating~~Expenditures ~~similarities~~below ~~within~~for ~~the~~additional ~~area,~~information ~~geologic~~regarding ~~considerations~~our ~~and~~investment ~~common~~in ~~cost~~oil ~~environments~~and ingas ~~this area~~properties.

53 55

Table of Contents

~~Proved~~Cash ~~Property~~flows ~~Impairment.~~provided Weby ~~assess~~financing ~~our~~activities. ~~proved~~Cash ~~oil~~provided ~~and~~by ~~gas~~financing ~~properties~~activities for ~~impairment~~the ~~whenever~~year ~~events~~ended orDecember ~~circumstances~~31, ~~indicate~~2020 ~~that~~decreased ~~the~~to ~~carrying~~$14.3 ~~value~~million ofas ~~the~~compared ~~assets~~to ~~may not be recoverable~~$49.6 Wemillion ~~estimate~~for the ~~expected~~year ~~future~~ended ~~cash~~December ~~flows~~31, of2020. We ~~our~~drew ~~oil~~$17.0 ~~and~~million ~~gas~~on ~~properties and compare these undiscounted cash flows to~~ the ~~carrying~~Revolver ~~value of~~in the ~~oil~~third ~~and~~quarter ~~gas~~of ~~properties~~2020 to ~~determine~~meet ifour ~~the~~working ~~carrying~~capital ~~value is recoverable~~needs. We ~~may~~This ~~apply~~was anpartially ~~additional~~offset ~~risk-adjustment~~by ~~factor~~a to$1.4 ~~the~~million ~~undiscounted~~required ~~cash~~repayment ~~flows~~made ~~from~~in ~~proved~~early ~~undeveloped~~July ~~reserves.~~2020 Ifafter ~~the~~we ~~carrying~~unwound ~~value~~a ~~exceeds~~derivative ~~the~~position. ~~estimated~~In ~~undiscounted~~January ~~future cash flows~~2020, we ~~will write~~paid ~~down~~lender ~~the~~and ~~carrying~~legal ~~amount~~fees oftotaling ~~the~~$1.0 ~~oil~~million ~~and gas properties~~ to ~~fair~~amend ~~value.~~our ~~The~~Revolving ~~factors~~Facility ~~used~~ to ~~determine~~increase ~~fair~~the ~~value~~borrowing ~~include,~~base ~~but~~to ~~are~~$210 ~~not~~million ~~limited~~(which ~~to,~~was ~~estimates~~subsequently ~~of reserves,~~reduced ~~future~~to ~~commodity~~$170 ~~prices,~~million ~~future~~following ~~production~~the ~~estimates,~~industry ~~estimated~~downturn). ~~future~~During ~~capital expenditures~~2019, ~~estimated~~we ~~future~~borrowed ~~operating~~$50.0 ~~costs,~~million ~~and~~on ~~discount~~our ~~rates~~Revolving ~~commensurate~~Facility ~~with~~to ~~the~~fund ~~risk~~a ~~associated~~portion ~~with realizing~~of ~~the~~our ~~projected~~2019 ~~cash~~drilling ~~flows~~program.

Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may incur impairment expense. As a result of lower commodity prices and their impact on our estimated future cash flows, we have continued to review our proved oil and gas properties for impairment. At December 31, 2019, using SEC defined pricing as described in Note 16, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by approximately $801 million, or 112%. As of December 31, 2019, our reserve estimate, updated with management’s future pricing assumptions as of that date, was higher than the SEC reserve value.

~~Unproved~~Capital ~~Property~~Expenditures Impairment. Unproved properties consist of costs incurred to acquire undeveloped leases as well as purchases of unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are initially capitalized, and when successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. We evaluate significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, or future plans to develop acreage.

~~Derivative~~The ~~Financial~~following ~~Instruments.~~table Wesummarizes ~~use~~our ~~derivative~~capital ~~financial~~expenditures ~~instruments~~incurred to(excluding ~~mitigate~~changes ~~our~~related ~~exposure~~ to changes in commodity prices arising in the normal course of business. We primarily utilize commodity price swap, option and costless collar contracts. We do not trade in derivative financial instruments for speculative purposes. None of our ~~derivative~~asset ~~contracts~~retirement ~~have~~obligation) ~~been designated as cash flow hedges~~ for ~~accounting purposes, and as a result, all of our derivative contracts are recorded in~~ the years ~~consolidated~~ending ~~financial statements at fair value~~December 31, ~~with~~2020 ~~changes~~and ~~in derivative fair value being recognized currently in earnings~~2019.

We determine the recorded amounts of our derivative instruments measured at fair value utilizing third-party valuation specialists, who utilize industry-standard models that consider various assumptions, including quoted forward prices for commodities, time to maturity, volatility and credit risk. We review these valuations, including the related model inputs and assumptions, and analyze changes in fair value measurements between periods. We corroborate such inputs, calculations and fair value changes using various methodologies, and review unobservable inputs for reasonableness utilizing relevant information from other published sources. We also utilize counterparty valuations to assess the reasonableness of our valuations. The values we report in our financial statements change as the assumptions used in these valuations are revised to reflect changes in market conditions (particularly those for oil and natural gas forward prices) or other factors, many of which are beyond our control.

Income Taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not, including judgments and assumptions about future taxable income and future operating conditions (particularly as related to prevailing oil and natural gas prices). For the year ended December 31, 2019, we did not recognize tax assets of $64.9 million as the recovery was not determined to be more likely than not. Some or all of these deferred tax assets could be recognized in future periods against future taxable income.


	Year ending December 31
(In $ ’000s)	2020		2019		Change in $	Change in %
Unproved	$	(15)	$	177	(192)	(108)
Proved		40,925		149,766	(108,841)	(73)
Total	$	40,910	$	149,943	(109,033)	(73)

~~Table of Contents~~

~~Additionally,~~Our ~~our~~capital ~~federal~~expenditures ~~and~~for ~~state~~proved ~~income~~properties ~~tax~~for ~~returns~~the ~~are~~year ~~generally~~ended ~~not~~December ~~filed~~31, ~~before~~2020 ~~the~~decreased ~~consolidated~~73% ~~financial~~to ~~statements are prepared~~$40.9 ~~Therefore~~million, weas ~~estimate~~compared ~~the~~to ~~tax~~$149.8 ~~basis~~million ofin ~~our~~the ~~assets~~prior ~~and~~year ~~liabilities~~as ata ~~the~~result ~~end~~ of ~~each~~our ~~period~~scaled asback ~~well~~development asplan ~~the~~in ~~effects~~light of ~~tax~~commodity ~~rate~~prices ~~changes, tax credits,~~ and ~~net~~our ~~operating~~financial ~~and~~condition. In ~~capital~~addition, ~~loss~~the ~~carryforwards~~third, fourth and ~~carrybacks.~~fifth ~~Adjustments~~amendments ~~related~~ to ~~differences between~~ the ~~estimates~~Term weLoan ~~use~~ and ~~actual~~fifth ~~amounts~~amendment weto ~~report are recorded in~~ the ~~periods~~Revolving inFacility ~~which~~limited ~~we file~~ our ~~income~~capital ~~tax~~expenditures ~~returns.~~(as ~~These~~defined ~~adjustments and changes~~ in ~~our~~the ~~estimates~~agreements) ofto ~~asset~~$5 ~~recovery~~million ~~and~~for ~~liability~~the ~~settlement~~period ~~could~~May ~~have~~1, an2020 ~~impact~~through onSeptember ~~our~~30, ~~results~~2020, ofand ~~operations~~to $11.1 ~~Revisions~~million tofor ~~our~~the ~~estimated~~period ~~effective~~May ~~tax~~1, ~~rate~~2020 ~~could~~through ~~increase~~December or31, ~~decrease~~2020. We ~~our~~were ~~reported~~in ~~income~~compliance ~~tax~~with ~~expense~~these ~~or benefit~~limits.

Our effective and statutory income tax rates could be impacted by the state income tax rates in which we operate, and the effective and statutory income tax rates are not significantly different as the amount of permanent differences resulting from treatment that differs for assets and liabilities for financial and tax reporting purposes is not significant. The tax impact of temporary differences, primarily oil and gas properties, is reflected in deferred income taxes. At December 31, 2019 and 2018, we had no unrecognized tax benefits that would impact our effective tax rate and we have not provided for interest or penalties related to uncertain tax positions.

~~Asset~~In ~~Retirement~~2020, ~~Obligations.~~our ~~Asset~~drilling ~~retirement~~and ~~obligations~~completion ~~(“ARO”) relate to future~~ costs ~~associated~~totaled ~~with~~$34.8 ~~the~~million, ~~plugging~~which ~~and~~included ~~abandonment~~costs ofto ~~oil~~add ~~and~~8.2 ~~gas~~net producing wells, ~~removal~~which ofwere ~~equipment~~turned ~~and facilities from leased acreage and returning such land~~ to ~~its~~sales ~~original condition~~ in ~~accordance~~February ~~with~~2020 ~~applicable~~(2.0 ~~local,~~net ~~state~~operated ~~and~~wells) ~~federal~~late ~~laws~~June as2020 ~~well as the terms of our lease agreements~~(4. ~~The~~0 ~~discounted~~net ~~fair~~operated ~~value~~wells) ofand aDecember ~~liability for an asset retirement obligation is recorded in the period in which it is incurred~~ (~~typically~~2.0 ~~when~~net aoperated ~~well is spud or acquired~~wells). We ~~with~~also ~~the~~invested ~~associated~~$2.2 ~~asset~~million ~~retirement~~into ~~cost~~shared ~~capitalized~~facility asprojects ~~part of the carrying cost of the oil~~ and ~~gas asset~~$2. ~~The~~2 ~~liability~~million isfor ~~accreted~~artificial ~~each~~lift ~~period through charges to DD&A expense,~~ and ~~the~~other ~~capitalized~~well ~~cost~~enhancements ~~is depleted~~ on aexisting ~~unit-of-production basis over the proved developed reserves of the related asset~~wells. ~~Revisions may occur due to changes in estimated abandonment costs or well economic lives, and such revisions result in adjustments to the related capitalized asset and corresponding liability.~~

Revenue Recognition. Our revenue is derived from the sale of produced oil, natural gas and NGLs. Revenue is recorded in the month the product is delivered to the purchaser, while payment is received up to 60 days after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically the differences have not been material.

~~Transfer~~In ~~of control drives the statement of operations classification of transportation~~2019, ~~gathering,~~our ~~processing,~~drilling and ~~marketing~~completion ~~expenses~~costs ~~(“fees~~totaled ~~and~~$125.0 ~~other~~million, ~~deductions”)~~which ~~within~~included ~~the~~costs ~~accompanying~~to ~~statements~~add ~~of operations~~22.3 ~~Fees~~net ~~and~~producing ~~other~~wells ~~deductions~~and ~~incurred~~there ~~prior~~were to2.0 ~~control~~additional ~~transfer~~net ~~are~~operated ~~recorded~~wells ~~within~~waiting ~~gathering,~~on ~~processing~~completion and ~~transportation~~0.3 ~~expense~~non ~~line~~operated ~~item~~wells onin the ~~accompanying~~process ~~statements~~ of ~~operations,~~being ~~while~~drilled. In ~~fees~~addition, ~~and~~we ~~other~~invested ~~deductions~~$13.6 ~~incurred~~million ~~subsequent~~into toshared ~~control~~facility ~~transfer~~projects ~~are~~during ~~recorded~~the asyear aended ~~reduction~~December of31, ~~revenue~~2019.

Recently Issued Accounting Pronouncements. See Note 1 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report for discussion of the recent accounting pronouncements.

~~Item 7A.~~Credit ~~Quantitative~~Facilities ~~and Qualitative Disclosures about Market Risk.~~

~~Not applicable.~~

~~Item 8~~We and our wholly owned subsidiary, SEI, are parties to the Term Loan, which is a syndicated $250.0 ~~Financial~~million ~~Statements~~second lien term loan with Morgan Stanley Capital Administrators Inc., as administrative agent, and ~~Supplementary~~the ~~Data~~Revolving Facility, which is a syndicated reserve-based revolver with Toronto Dominion (Texas) LLC, as administrative agent. As of December 31, 2020, we had a borrowing base of $190.0 million, elected commitment of $170 million, $130.6 million of borrowings outstanding and $16.4 million of letters of credit in place under the Revolving Facility. As a result of the commencement of the Chapter 11 Cases, the lender’s commitments under the Revolving Facility have been terminated. We are therefore unable to make additional borrowings or issue additional letters of credit under the Revolving Facility.

~~The financial statements and supplementary information required by this Item appears on pages 60 through 100 of this annual report.~~

~~Item 9~~Effective January 2021, interest on the Revolving Facility accrued at a rate equal to Prime plus a margin, ranging from 1.50% ~~Changes~~to 2.50%, depending on the level of funds borrowed, plus post-default interest of 2%. The default interest rate was in ~~and~~place ~~Disagreements~~from ~~with~~December ~~Accountants~~18, 2020 through March 9, 2021. Interest on ~~Accounting~~the ~~and~~Term ~~Financial~~Loan ~~Disclosure~~accrues at LIBOR (with a LIBOR floor of 1. 0%) plus 10.0%, of which 2% of the applicable margin is payable-in-kind (effective May 30, 2020). Beginning January 2021, an additional post-default interest rate of 2% began to accrue on the Term Loan.

~~None.~~ 56

55 Table of Contents

~~Table~~During the Chapter 11 Cases, we expect the DIP Facility will fund a portion of ~~Contents~~ our cash requirements. Interest on the DIP Facility will accrue at a rate equal to LIBOR (with a LIBOR floor of 1.0%) plus 8%.

~~Item 9A. Controls and Procedures.~~

~~Evaluation~~The DIP Facility agreement includes conditions precedent, representations and warranties, affirmative and negative covenants, and events of ~~Disclosure~~default ~~Controls~~customary for financings of this type and ~~Procedures~~ size. The DIP Facility will mature on the date which is the earliest of (a) June 14, 2021, (b) the effective date of the Prepackaged Plan or (c) the date all DIP Facility loans become due and payable, whether by acceleration or otherwise.

AsWe ofmade ~~December 31,~~an ~~2019,~~initial ~~our~~draw ~~management, with the participation~~ of ~~our~~$10 ~~Chief~~million ~~Executive~~under ~~Officer and Chief Financial Officer, has evaluated~~ the ~~effectiveness~~DIP ofFacility ~~our disclosure controls and procedures (as defined~~ in ~~Rule 13a‑15(e) under~~March ~~the Exchange Act)~~2021. We ~~Disclosure~~may ~~controls~~make ~~and~~additional ~~procedures~~draws ~~are~~of ~~designed~~up to ~~provide~~$35 ~~reasonable~~million ~~assurance~~during ~~that~~ the ~~information~~Chapter we11 ~~are~~Cases. An ~~required~~additional to$5 ~~disclose~~million in ~~the~~DIP ~~reports~~Facility weloans ~~file or submit under the Exchange Act~~ is ~~recorded,~~available ~~processed,~~with ~~summarized~~consent ~~and reported within the time periods specified in the rules and forms~~ of the ~~SEC~~DIP ~~and~~Facility ~~that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures~~lenders. There are inherent limitations to the effectiveness of any disclosure controls and procedures system, including the possibility of human error and circumventing or overriding them. Even if effective, disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that due to the material weakness in our internal control over financial reporting related to the IFRS to US GAAP conversion as described below, the Company’s disclosure controls and procedures were not effective as of December 31, 2019.

~~Management’s~~Off-Balance ~~Annual~~Sheet ~~Report on Internal Control over Financial Reporting~~ Arrangements

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2019 based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework (2013). Based on this assessment, our Chief Executive Officer and Chief Financial Officer concluded that a material weakness in internal control over financial reporting existed as of December 31, 2019, as described below.

AWe ~~material~~do ~~weakness~~not ishave aany ~~deficiency,~~off-balance orsheet ~~combination~~arrangements ofthat ~~deficiencies~~have, inor ~~internal~~are ~~control~~reasonably ~~over~~likely ~~financial~~to ~~reporting~~have, ~~such that there is~~ a ~~reasonable~~current ~~possibility~~or ~~that~~future aeffect ~~material~~on ~~misstatement~~our offinancial ~~the~~statements, ~~annual~~revenues or ~~interim~~expenses, ~~financial~~results ~~statements~~of ~~will~~operations, ~~not~~liquidity, becapital ~~prevented~~expenditures or ~~detected~~capital onresources athat ~~timely~~is ~~basis~~material to investors.

In connection with the conversion of our financial statements from IFRS to U.S. GAAP following our Redomiciliation, an analysis of the valuation allowance related to deferred tax assets as of December 31, 2019 was not prepared in a timely manner. We did not have a process for identifying when an analysis should be prepared other than on an annual basis. When the analysis was prepared, it resulted in a $3.7 million adjustment to deferred income tax benefit and to the associated balance sheet account. This control deficiency created a reasonable possibility that a material misstatement to the consolidated financial statement would not have been prevented or detected on a timely basis, and therefore management concluded that the deficiency represented a material weakness in internal control over financial reporting, and that internal control over control over financial reporting was not effective as of December 31, 2019.

WeCritical ~~have~~Accounting ~~updated~~Policies ~~our policy~~ and ~~processes~~Estimates ~~to require that we perform an update of the analysis of the valuation allowance related to deferred tax assets for the tax implications of non-recurring events when a nonrecurring event occurs.~~

~~Changes in internal control over financial reporting~~

~~Other~~Our ~~than~~discussion ~~the~~and ~~material~~analysis ~~weakness~~of ~~associated~~our ~~with~~financial ~~the~~condition ~~IFRS~~and toresults USof ~~GAAP~~operations ~~conversion~~are ~~discussed~~based ~~above~~upon our consolidated financial statements, ~~there~~which ~~was~~have nobeen ~~change~~prepared in ~~our~~accordance ~~internal~~with ~~control~~GAAP. ~~over~~The preparation of the consolidated financial ~~reporting~~statements ~~that~~in ~~occurred~~conformity ~~during~~with ~~the~~GAAP ~~quarter~~requires ~~ended~~management ~~December~~to ~~31,~~make ~~2019,~~estimates and assumptions that ~~has~~affect ~~materially~~the ~~affected~~amounts reported in our financial statements. Actual results could differ from our estimates and assumptions, orand isthese ~~reasonably~~differences ~~likely~~could result in material changes to ~~materially~~our ~~affect,~~financial statements. The following discussion presents information about our ~~internal~~most ~~control~~critical ~~over~~accounting policies and estimates. Our significant accounting policies are further described in Note 1 to our audited consolidated financial ~~reporting~~statements included in “Item 8. Financial Statements and Supplemental Data” of this annual report.

~~Table~~Estimates of ~~Contents~~ Oil and Gas Reserve Quantities. The estimated quantities of oil, natural gas and NGL reserves are integral to the calculation of DD&A and to assessments of possible impairment of assets. Discounted future net cash flows derived from our reserve estimates were also utilized in calculating the fair value of our oil and natural gas for the write-down of proved properties in the third quarter of 2020. Proved oil and gas reserves are those quantities of oil and gas 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. These estimates require significant judgements to be made regarding future development and production costs, development plans and fiscal regimes. The estimates of reserves may change from period to period as the economic assumptions used to estimate the reserves can change from period to period and as additional geological data is generated during the course of operations. Ryder Scott prepared 100% of our proved reserve estimates as of December 31, 2020 and 2019. In connection with Ryder Scott performing their independent reserve estimations, we furnish them with the following information that they review: (i) technical support data, (ii) technical analysis of geologic and engineering support information, (iii) economic and production data and (iv) our well ownership interests and (v) expected future development plans.

Because we are an “emerging growth company” under the JOBS Act, our independent registered public accounting firm, Deloitte & Touche LLP, is not required to issue an attestation report on our internal control over financial reporting.

~~Item~~Depreciation, 9BDepletion and Amortization. ~~Other~~The ~~Information~~quantities of estimated proved oil and gas reserves are a significant component of our calculation of DD&A expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserve quantities were revised upward or downward, net income would increase or decrease, respectively.

On May 8, 2020 and May 11, 2020, respectively, we obtained waivers from its Revolving Facility and Term Loan lenders to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and with respect to the defaults arising from a failure to deliver audited consolidated financial statements for the year ended December 31, 2019 and related reports and certificates by the applicable deadline. These waivers were effective as of April 29, 2020, subject to the conditions set forth in the waivers.

~~Under the Revolving Facility waiver, we may not draw any additional funds on the Revolving Facility until completion of our second quarter 2020 borrowing base redetermination.~~

Under the Term Loan waiver, we agreed to amend certain provisions in the Term Loan, as to be mutually agreed with the Term Loan lenders, within 15 days from the execution date. The waiver under the Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion. Failure to enter into such amendment with respect to the Term Loan within 15 days (or a similar amendment with respect to the Revolving Facility on the date the Term Loan is amended) would constitute an event of default under the credit facilities, in which case the amounts outstanding under the credit facilities could be accelerated and become immediately due and payable. While management believes that it will finalize such amendments within the required time frame, there can be no assurance that management’s efforts will result in any finalizing these amendments or the ultimate terms of any such amendments. 57

~~With~~Table ~~respect to the Term Loan, we have engaged in preliminary discussions regarding the terms~~ of the required amendment. In addition, we have agreed to explore in good faith with its Term Loan lenders options to reduce our overall level of indebtedness and leverage and limit capital and general and administrative expenditures for some specified period of time. As described above, the lenders under the Revolving Facility may request corresponding amendments under the Revolving Facility. Contents

~~The~~DD&A ~~forgoing~~of ~~summary~~the cost of ~~the~~proved ~~waivers~~oil and gas properties is ~~qualified~~calculated inusing ~~its~~the ~~entirety~~unit-of-production bymethod. The ~~reference~~reserve base used to ~~the~~calculate ~~full~~depreciation, ~~text~~depletion ofand ~~such~~amortization ~~waivers,~~for ~~copies~~proved leasehold acquisition costs is the sum of ~~which~~proved ~~are~~developed ~~attached~~reserves asand ~~Exhibit 10~~proved undeveloped reserves.19 With respect to lease and ~~Exhibit~~well 10equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.20 We tohave ~~this~~one ~~annual~~unit-of-production ~~report~~field, ~~respectively~~the Eagle Ford formation. This method considers the geographic concentration, operating similarities within the area, geologic considerations and ~~incorporated~~common ~~herein~~cost byenvironments ~~reference~~in this area.

~~PART III~~

~~Item~~Proved Property Impairment. We assess our proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted cash flows to the carrying value 10of the oil and gas properties to determine if the carrying value is recoverable. We may apply an additional risk-adjustment factor to the undiscounted cash flows from proved undeveloped reserves. If the carrying value exceeds the estimated undiscounted future cash flows, we will ~~Directors~~write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, ~~Executive~~but ~~Officers~~are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating costs, and ~~Corporate~~discount ~~Governance~~rates commensurate with the risk associated with realizing the projected cash flows.

The information concerning our executive officers and directors in response to this item will be included in the Proxy Statement for our 2020 Annual Meeting of Stockholders and is incorporated herein by reference.

~~Item~~Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual 11results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may incur impairment expense. For 2020, the pricing used in our internal estimate of future cash flows was based on WTI strip prices for the first 24 months, with the price escalating up to a terminal price of $50 in year five and forward. As a result of ~~Executive~~lower ~~Compensation~~commodity prices at September 30, 2020 and the resulting impact on our estimated future cash flows, the carrying costs of our proved property exceeded our estimated cash flows and we recognized impairment expense of $331. 8 million. Following the September 30, 2020 impairment and largely due to the increase in WTI strip pricing at December 31, 2020, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties.

~~The information required by this item will be included in our Proxy Statement for our 2020 Annual Meeting of Stockholders, and is incorporated herein by reference.~~

~~Item 12~~Unproved Property Impairment. ~~Security~~Unproved ~~Ownership~~properties consist of ~~Certain~~costs ~~Beneficial~~incurred ~~Owners~~to acquire undeveloped leases as well as purchases of unproved reserves. Undeveloped lease costs and ~~Management~~unproved reserve acquisitions are initially capitalized, and ~~Related~~when ~~Stockholder~~successful ~~Matters~~wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. We evaluate significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, or future plans to develop acreage.

~~The information required by this item will be included in our Proxy Statement for our 2020 Annual Meeting of Stockholders and is incorporated herein by reference.~~

57 Derivative Financial Instruments. We use derivative financial instruments to mitigate our exposure to changes in commodity prices arising in the normal course of business. We primarily utilize commodity price swap, option and costless collar contracts. We do not trade in derivative financial instruments for speculative purposes. None of our derivative contracts have been designated as cash flow hedges for accounting purposes, and as a result, all of our derivative contracts are recorded in the consolidated financial statements at fair value, with changes in derivative fair value being recognized currently in earnings.

~~Table of Contents~~

~~Item 13~~We determine the recorded amounts of our derivative instruments measured at fair value utilizing third-party valuation specialists, who utilize industry-standard models that consider various assumptions, including quoted forward prices for commodities, time to maturity, volatility and credit risk. We ~~Certain~~review ~~Relationships~~these valuations, including the related model inputs and ~~Related~~assumptions, ~~Transactions~~and analyze changes in fair value measurements between periods. We corroborate such inputs, calculations and ~~Director~~fair ~~Independence~~value changes using various methodologies, and review unobservable inputs for reasonableness utilizing relevant information from other published sources. We also utilize counterparty valuations to assess the reasonableness of our valuations. The values we report in our financial statements change as the assumptions used in these valuations are revised to reflect changes in market conditions (particularly those for oil and natural gas forward prices) or other factors, many of which are beyond our control.

~~The information required by this item will be included in our Proxy Statement for our 2020 Annual Meeting of Stockholders and is incorporated herein by reference.~~ 58

~~Item 14.~~Table ~~Principal~~of ~~Accounting Fees and Services.~~ Contents

~~The~~Income ~~information~~Taxes. ~~required~~We byprovide ~~this~~for ~~item~~deferred ~~will~~income betaxes ~~included~~on the difference between the tax basis of an asset or liability and its carrying amount in our ~~Proxy~~financial ~~Statement~~statements. ~~for~~This ~~our~~difference ~~2020~~will ~~Annual~~result ~~Meeting~~in taxable income or deductions in future years when the reported amount of ~~Stockholders~~the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is ~~incorporated~~more ~~herein~~likely bythan ~~reference~~not, including judgments and assumptions about future taxable income and future operating conditions (particularly as related to prevailing oil and natural gas prices). For the year ended December 31, 2020, we did not recognize tax assets of $139.7 million as the recovery was not determined to be more likely than not. Some or all of these deferred tax assets could be recognized in future periods against future taxable income.

~~PART IV~~

~~Item 15~~Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. ~~Exhibits~~Therefore, ~~Financial~~we ~~Statement~~estimate ~~Schedules~~the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations. Revisions to our estimated effective tax rate could increase or decrease our reported income tax expense or benefit.

Financial Statements. Refer to the Index to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report for a list of all financial statements filed as part of this report.

~~Financial~~Our ~~Statement Schedules. All~~effective ~~schedules~~and ~~are~~statutory ~~omitted~~income ~~since~~tax rates could be impacted by the ~~required~~state ~~information~~income istax ~~not~~rates ~~present~~in which we operate, orand isthe effective and statutory income tax rates are not ~~present~~significantly indifferent ~~amounts~~as ~~sufficient~~the toamount ~~require~~of ~~submission~~permanent differences resulting from treatment that differs for assets and liabilities for financial and tax reporting purposes is not significant. The tax impact of ~~the~~temporary ~~schedule~~differences, orprimarily ~~because~~oil ~~the~~and ~~information~~gas ~~required~~properties, is ~~included~~reflected in ~~our~~deferred ~~Consolidated~~income ~~Financial~~taxes. ~~Statements~~At orDecember 31, ~~the~~2020 ~~Notes~~and ~~thereto~~2019, ~~included~~we inhad ~~Item~~no 8.unrecognized ~~“Financial~~tax ~~Statements~~benefits that would impact our effective tax rate and ~~Supplementary~~we ~~Data”~~have ofnot ~~this~~provided ~~annual~~for ~~report~~interest or penalties related to uncertain tax positions.

~~Exhibits. The exhibits listed in the accompanying exhibit index are filed (except where otherwise indicated) as part of this report.~~

~~Item~~Revenue Recognition. Our revenue is derived from the sale of produced oil, natural gas and NGLs. Revenue is recorded in the 16month the product is delivered to the purchaser, while payment is received up to 60 days after delivery. ~~Form~~At the end of each ~~10‑K~~month, ~~Summary~~we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically the differences have not been material.

~~None.~~

58 Transfer of control drives the statement of operations classification of transportation, gathering, processing, and marketing expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within gathering, processing and transportation expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of revenue.

~~Table of Contents~~

~~REPORT~~Recently OFIssued ~~INDEPENDENT~~Accounting ~~REGISTERED~~Pronouncements. ~~PUBLIC~~See ~~ACCOUNTING~~Note ~~FIRM~~ 1 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report for discussion of the recent accounting pronouncements.

~~To the shareholders and the Board of Directors of Sundance Energy Inc.~~

~~Opinion~~Item 7A. onQuantitative ~~the~~and ~~Financial~~Qualitative ~~Statements~~ Disclosures about Market Risk.

We have audited the accompanying consolidated balance sheets of Sundance Energy Inc. and its subsidiaries (the "Company") as of December 31, 2019 and 2018, the related consolidated statements of operations and comprehensive loss, changes in equity, and cash flows, for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

~~Basis~~Not ~~for~~applicable. ~~Opinion~~

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

~~We conducted our audits in accordance with the standards of the PCAOB~~Item 8. ~~Those~~Financial ~~standards~~Statements ~~require that we plan~~ and ~~perform~~Supplementary ~~the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud~~Data. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

~~Going~~The ~~Concern~~ financial statements and supplementary information required by this Item appears on pages 77 through 117 of this annual report.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company anticipates that it may not comply with the covenant requirements of the Credit Facilities within the next 12 months following the date of this report, which would accelerate the amounts outstanding under the credit facilities, making it currently due and payable. The Company does not have sufficient liquidity to repay such outstanding amounts. This issue raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

~~/s/~~Item 9. ~~Deloitte~~Changes &in ~~Touche~~and ~~LLP~~ Disagreements with Accountants on Accounting and Financial Disclosure.

~~Denver, CO~~

~~May~~None. ~~14, 2020~~

~~We have served as the Company's auditor since 2019.~~ 59

59 Table of Contents

~~Table~~Item of9A. ~~Contents~~ Controls and Procedures.

~~SUNDANCE ENERGY INC.~~

~~CONSOLIDATED~~Evaluation ~~BALANCE~~of ~~SHEETS~~ Disclosure Controls and Procedures

~~(all amounts in thousands except share and per share data)~~

	December 31,
	2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	12,382	$	1,581
Accounts receivable trade and other		27,020		21,249
Derivative financial instruments		1,215		24,315
Income tax receivable		3,555		2,384
Other current assets		3,616		3,547
Assets held for sale		—		23,471
Total current assets		47,788		76,547
Oil and gas properties, successful efforts method		1,122,908		986,548
Less: accumulated depletion, depreciation and amortization		(379,961)		(293,598)
Total oil and gas properties, net		742,947		692,950
Other long-term assets:
Other property and equipment, net of accumulated depreciation of $3,419 and $2,823		1,963		1,354
Income tax receivable		1,172		2,344
Operating lease right-of-use assets		17,331		—
Derivative financial instruments		878		8,003
Other long-term assets		1,835		2,150
TOTAL ASSETS	$	813,914	$	783,348
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable trade	$	43,284	$	45,137
Accrued liabilities		26,409		25,285
Derivative liabilities		4,394		436
Operating lease liabilities - current		7,720		—
Liabilities related to assets held for sale		—		193
Total current liabilities		81,807		71,051
Long-term liabilities:
Long-term debt		353,490		300,804
Asset retirement obligations		3,653		3,296
Operating lease liabilities - long term		9,611		—
Derivative financial instruments		3,669		2,578
Deferred tax liabilities		7,138		11,656
Other long-term liabilities		1,149		1,474
Total long-term liabilities		378,710		319,808
Total liabilities		460,517		390,859
Commitments and contingencies (Note 14)
Stockholders’ Equity:
Common stock, $0.001 value, 100,000,000 shares authorized; 6,875,672 issued and outstanding at December 31, 2019 and 6,874,622 shares issued and outstanding at December 31, 2018.		7		7
Additional paid-in capital		633,246		632,742
Accumulated deficit		(279,144)		(239,554)
Accumulated other comprehensive loss		(712)		(706)
Total stockholders’ equity		353,397		392,489
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	813,914	$	783,348

As of December 31, 2020, our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act). There are inherent limitations to the effectiveness of any disclosure controls and procedures system, including the possibility of human error and circumventing or overriding them. Even if effective, disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives.

~~The~~Based ~~accompanying~~on ~~notes~~this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of December 31, 2020 to provide reasonable assurance that the information we are anrequired ~~integral~~to ~~part~~disclose in the reports we file or submit under the Exchange Act are (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of ~~these~~the ~~consolidated~~SEC ~~financial~~and ~~statements~~ (ii) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures.

~~Table~~Management’s ofAnnual ~~Contents~~ Report on Internal Control over Financial Reporting

~~SUNDANCE ENERGY INC.~~

~~CONSOLIDATED~~Our ~~STATEMENTS~~management OFis ~~OPERATIONS~~responsible ~~AND~~for ~~COMPREHENSIVE~~establishing ~~LOSS~~ and maintaining adequate internal control over financial reporting. Our management assessed the effectiveness of our internal control over financial reporting as of the year ended December 31, 2020. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework (2013). Based on management’s assessment and those criteria, our management believes that we maintained effective internal control over financial reporting as of December 31, 2020.

~~(all~~This ~~amounts~~annual inreport ~~thousands~~does ~~except~~not ~~share~~include an attestation report of our registered independent public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the Securities and ~~per~~Exchange ~~share~~Commission ~~data)~~ that permit us to provide only the management's report in this annual report.

			For the year ended December 31,
Revenues:			2019		2018
	Oil sales		$	177,853	$	140,240
	Natural gas sales			12,553		12,025
	Natural gas liquid sales			13,174		12,668
		Total revenues		203,580		164,933
Operating expenses:
	Lease operating and workover expense			33,681		33,957
	Gathering, processing and transportation expense			17,086		8,633
	Production taxes			11,484		9,270
	Exploration expense			337		3,339
	Depreciation, depletion and amortization expense			92,334		62,814
	Impairment expense			9,990		43,828
	General and administrative expense			22,276		30,539
	Loss (gain) on commodity derivative financial instruments			20,542		(40,216)
	Other expense (income), net			1,900		(48)
		Total operating expenses		209,630		152,116
Income (loss) from operations:				(6,050)		12,817
Other income (expense)
	Interest expense			(38,058)		(28,631)
	Gain on foreign currency derivative financial instruments			—		6,838
		Total other expense		(38,058)		(21,793)
Loss before income taxes				(44,108)		(8,976)
Income taxes
	Current expense			—		(2,301)
	Deferred benefit (expense)			4,518		(11,656)
		Total income tax benefit (expense)		4,518		(13,957)
Net loss			$	(39,590)	$	(22,933)
Loss per common share
		Basic and diluted	$	(5.76)	$	(4.38)
Weighted average shares outstanding
		Basic and diluted		6,874,170		5,236,524
Comprehensive loss
	Net loss		$	(39,590)	$	(22,933)
	Other comprehensive income (loss):
		Foreign currency translation		(6)		428
Total comprehensive loss			$	(39,596)	$	(22,505)

Changes in internal control over financial reporting

~~The~~There ~~accompanying~~was ~~notes~~no ~~are~~change anin ~~integral~~our ~~part~~internal control over financial reporting that occurred during the fourth quarter of ~~these~~2020, ~~consolidated~~that has materially affected, or is reasonably likely to materially affect, our internal control over financial ~~statements~~ reporting.

61 Item 9B. Other Information.

~~Table of Contents~~

~~SUNDANCE ENERGY INC~~None.

~~CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY~~

~~(all amounts in thousands except share and per share data)~~ 60

										Accumulated
										other
		Common stock				Additional		Accumulated		comprehensive
		Shares	Amount			Paid-In Capital		Deficit		loss	Total
BALANCES - January 1, 2018		1,253,250	$	1	$	389,013	$	(216,621)	$	(1,134)	$	171,259
	Fractional shares issued upon reverse split	10		—		—		—		—		—
	Shares issued in connection with private placement	5,614,446		6		253,511		—		—		253,517
	Private placement offering costs, net of tax	—		—		(10,297)		—		—		(10,297)
	Stock-based compensation	6,916		—		515		—		—		515
	Net loss	—		—		—		(22,933)		—		(22,933)
	Foreign currency translation	—		—		—		—		428		428
BALANCES - December 31, 2018		6,874,622	$	7	$	632,742	$	(239,554)	$	(706)	$	392,489
	Stock-based compensation	1,050		—		504		—		—		504
	Net loss	—		—		—		(39,590)		—		(39,590)
	Foreign currency translation	—		—		—		—		(6)		(6)
BALANCES - December 31, 2019		6,875,672	$	7	$	633,246	$	(279,144)	$	(712)	$	353,397

Table of Contents

~~The accompanying notes are an integral part of these consolidated financial statements~~ PART III

~~Table~~Item 10. Directors, ofExecutive ~~Contents~~ Officers and Corporate Governance.

~~SUNDANCE ENERGY INC.~~

~~CONSOLIDATED~~The ~~STATEMENTS~~Company’s OFBoard ~~CASH~~of ~~FLOWS~~ Directors (the “Board”) and the executive officers of the Company are:

~~(all amounts in thousands except for share and per share data)~~

					Year Ended December 31,

						2019		2018
Name		Age		Title and Position
CASH FLOWS FROM OPERATING ACTIVITIES
Stephen J. McDaniel(1)		59		Chairman of the Board & Director
	Net loss				$	(39,590)	$	(22,933)
Eric P. McCrady		44		Director, President & Chief Executive Officer
	Adjustments to reconcile net loss to net cash provided by operating activities:
Judith D. Buie(2)(3)		51		Director
		Depreciation, depletion and amortization expense				92,334		62,814
Damien A. Hannes(2)(4)		64		Director
		Impairment expense				9,990		43,828
H. Weldon Holcombe(3)(4)		68		Director
		Loss on abandonment of unproved oil and gas properties				—		550
Neville W. Martin(1)(3)		71		Director
		Stock-based compensation				504		515
Thomas L. Mitchell(2)(4)		60		Director
		Deferred income tax (benefit) expense				(4,518)		11,656
Cathy L. Anderson		65		Executive Vice President, Chief Financial Officer & Treasurer
		Gain on foreign currency derivative financial instruments				—		(6,838)
Christopher I. Humber		47		Executive Vice President, General Counsel & Secretary
		Loss (gain) on commodity derivative financial instruments				20,542		(40,216)
James R. Redfearn		42		Executive Vice President, Chief Operating Officer
		Net cash settlements received on commodity derivative contracts				11,258		(599)
		Premiums (paid) received on commodity derivative contracts				(152)		634
		Unrealized loss on interest rate swaps				3,625		2,137
		Amortization of deferred financing fees				3,234		2,281
		Write-off of deferred financing fees				—		251
		Other				(83)		—
	Changes in assets and liabilities:
		Accounts receivable trade and other				2,539		(17,728)
		Accounts payable trade				2,512		9,014
		Accrued liabilities				9,803		(1,144)
		Other assets and liabilities, net				(769)		(408)
			Net cash provided by operating activities			111,229		43,814
CASH FLOWS FROM INVESTING ACTIVITIES
	Capital expenditures for proved oil and gas properties					(166,646)		(168,956)
	Capital expenditures for unproved oil and gas properties					(319)		(1,790)
	Acquisition of oil and gas properties					—		(215,790)
	Proceeds from the sale of oil and gas properties					17,383		100
	Other property and equipment					(407)		(352)
			Net cash used in investing activities			(149,989)		(386,788)
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from borrowings					50,000		315,000
	Repayments of borrowings					—		(210,194)
	Payments of debt issuance costs					(232)		(16,040)
	Proceeds from issuance of common shares					—		253,517
	Equity offering costs					—		(10,293)
	Receipts from foreign currency derivatives					—		6,838
	Principal payments on finance lease obligations					(187)		(11)
			Net cash provided by financing activities			49,581		338,817
			Net change in cash and cash equivalents			10,821		(4,157)
CASH AND CASH EQUIVALENTS
			Beginning of year			1,581		5,761
			Effect of exchange rates on cash			(20)		(23)
			End of year		$	12,382	$	1,581
SUPPLEMENTAL CASH FLOW DISCLOSURES
	Income taxes paid				$	—	$	2,301
	Interest paid, net of amounts capitalized				$	26,203	$	26,359
NON-CASH INVESTING AND FINANCING ACTIVITIES
	Accounts payable and accrued expenses for oil and gas properties				$	25,000	$	38,508

~~The accompanying notes are an integral part of these consolidated financial statements~~

63 (1) Member of Nominating and Corporate Governance Committee

~~Table~~(2) Member of ~~Contents~~ Audit Committee

~~SUNDANCE~~(3) ~~ENERGY~~Member ~~INC.~~ of Reserves Committee

~~NOTES~~(4) TOMember ~~CONSOLIDATED~~of ~~FINANCIAL~~Compensation ~~STATEMENTS~~ Committee

~~NOTE 1 – BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~

~~Description~~Set forth below is biographical information about each of ~~Operations~~ the Company’s executive officers and directors.

On November 26, 2019, a new Delaware corporation named Sundance Energy Inc. (the “Company”) acquired all of the issued and outstanding ordinary shares of Sundance Energy Australia Limited (“SEAL”), an Australian Company, pursuant to a Scheme of Arrangement under Australian law (the “Scheme”) which was approved by SEAL’s shareholders on November 8, 2019 and the Federal Court of Australia on November 14, 2019. These events are collectively referred to as the “Redomiciliation”. Prior to the Redomiciliation, the Company’s ordinary shares were listed on the Australian Securities Exchange (“ASX”) and Sundance Energy Inc. had no business or operations. Following the Redomiciliation, the business and the operations of Sundance Energy Inc. consist solely of the historical business and operations of SEAL and its subsidiaries.

InStephen J. McDaniel was appointed to the ~~Redomiciliation~~Board in December 2019, ~~all~~and ~~outstanding~~is ~~SEAL~~our ~~ordinary~~current ~~shares~~Chairman. Mr. McDaniel also has served as an independent director of Ultra Petroleum Corporation from 2006 to 2020 and is presently serving on ~~November~~the 26Board of Directors of Encino Energy, ~~2019~~a $2 billion private exploration and production company, ~~were~~and ~~cancelled~~Bazean Corporation, an oil and ~~shares~~gas focused technology company. Mr. McDaniel previously served as a director of ~~the~~Midstates Petroleum Company’s, ~~common~~where ~~stock~~he was previously President and Chief Executive Officer and, ~~par~~later, ~~value~~non-executive $0Chairman.~~001~~ Since ~~per share~~2013, ~~were~~Mr. McDaniel ~~issued~~has served on the Executive Board of the Lone Star Chapter of Big Brothers Big Sisters. ~~Each~~ His previous experience included approximately ten years of ~~SEAL’s~~oil ~~shareholders~~and ~~received~~gas ~~one~~investment ~~share~~banking, the majority of which was with Merrill Lynch where he held the ~~Company’s~~position ~~common~~of ~~stock~~Managing inDirector. He ~~exchange~~began ~~for~~his ~~100~~career ~~SEAL~~with ~~ordinary~~Conoco ~~shares~~in 1983 where he held a variety of engineering, operations, and business development positions.

The purpose of the Redomiciliation was to reorganize the operations of SEAL, a public company incorporated under the laws of the State of South Australia, into a structure whereby the ultimate parent company of the Sundance group of companies would be a Delaware corporation. In connection with the Redomiciliation, the ordinary shares of SEAL were delisted from the ASX, and the common stock of Sundance Energy Inc. began trading on the Nasdaq Global Market on November 26, 2019 under the ticker symbol “SNDE”, the same symbol under which SEAL’s American Depository Shares were traded on Nasdaq Global Market prior to the implementation of the Redomiciliation. Immediately following the effectiveness of the Redomiciliation, SEAL distributed all of its assets to Sundance Energy Inc., and Sundance Energy Inc. assumed all of the liabilities of SEAL.

~~Sundance~~The ~~Energy~~Board ~~Inc.~~believes isthat anMr. McDaniel ~~independent~~possesses ~~oil~~specific ~~and~~attributes ~~gas~~that ~~company engaged~~qualify inhim ~~the~~to ~~development,~~serve ~~production~~as ~~and~~a ~~exploration~~director of ~~oil~~the Company, ~~natural~~including ~~gas~~his ~~and~~significant ~~natural~~oil and gas ~~liquids~~managerial ~~(“NGLs”)~~and ~~primarily~~operational ~~targeting~~experience, ~~the~~his ~~Eagle~~energy ~~Ford~~investment ~~basin~~banking inbackground, ~~South~~and ~~Texas~~his financial expertise.

~~Basis of Preparation~~

~~Prior~~Eric toP. ~~the~~McCrady ~~Redomiciliation~~has served as our President & Chief Executive Officer since April 2011, ~~SEAL~~and ~~reported~~as ~~its~~a ~~consolidated~~member ~~financial~~of ~~statements~~the inBoard ~~accordance~~since ~~with~~November ~~International~~2011. He also served as our Chief Financial ~~Reporting~~Officer ~~Standards~~from ~~(“IFRS”)~~June 2010 until becoming President & Chief Executive Officer in 2011. ~~Following~~ ~~the~~Mr. ~~Redomiciliation~~McCrady also serves as a director, ~~the~~President ~~Company~~& ~~retroactively~~Chief ~~transitioned~~Executive Officer of Sundance Energy, Inc., a Colorado corporation, which is our primary operating subsidiary. Mr. McCrady has over 20 years of entrepreneurial experience and he continues to ~~accounting~~lead ~~principles~~the ~~generally~~Sundance ~~accepted~~team that built a 47,000 net acre position in the ~~United~~Eagle ~~States~~Ford ofthrough ~~America~~asset ~~(“GAAP”)~~acquisitions and ~~applied~~direct ~~GAAP~~leasing, ~~retrospectively~~including ~~for~~the ~~all~~2018 ~~prior~~acquisition ~~periods~~of ~~presented. The~~approximately ~~Company’s~~22,000 ~~consolidated~~net ~~financial~~acres ~~statements~~from ~~have~~Pioneer ~~been~~Energy, ~~prepared~~Inc. inand ~~accordance~~its ~~with~~partners. ~~GAAP~~Previously, Mr. McCrady and ~~Securities~~the Sundance team built and ~~Exchange~~successfully ~~Commission~~monetized ~~(“SEC”)~~positions ~~rules~~in the Williston, DJ and ~~regulations~~Anadarko basins. Prior to Sundance Energy, McCrady had over 6 years focused on corporate finance, acquisitions, divestitures, and ~~include~~merger ~~the~~and ~~accounts~~acquisition ofarena specific to the ~~Company~~energy ~~and~~sector, ~~its~~while ~~consolidated~~at ~~subsidiaries. All~~The ~~intercompany~~Broe ~~balances~~Group, a Denver-based private investment firm, as well as being a founder and ~~transactions~~member ~~have~~of ~~been~~Trilogy ~~eliminated~~Resources, a DJ Basin startup that was successfully sold in ~~consolidation~~2013.

64 61

Table of Contents

~~Going~~Judith ~~Concern~~ D. Buie was appointed to the Board in February 2019. Ms. Buie has spent over 30 years in the upstream oil and gas business tailoring investment strategies to capture upside and mitigate risk, leading business development initiatives; and managing oil and gas fields through different commodity and life cycles. Ms. Buie currently serves on the Board of Directors for Enerplus Corporation (NYSE: ERF), an independent North American oil and gas exploration and production company, and FlowStream Vintage I Ltd, an international company which owns oil and gas revenue streams. From 2012-2017, Ms. Buie was Co-President and SVP Engineering for RPM Energy Management LLC, a private company which works exclusively with KKR to evaluate and manage oil and gas investments, including multiple joint ventures in the Eagle Ford. Prior to RPM, she held a variety of leadership and technical positions with Newfield Exploration, BP, Vastar Resources, and ARCO. Ms. Buie received a B.S. in Chemical Engineering from Texas A&M University.

The accompanying consolidated financial statements are prepared in accordance with GAAP applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

InThe ~~March~~Board ~~2020,~~believes ~~the~~that ~~prevailing market price for oil prices decreased from an average of approximately $60 per barrel for December 2019 to less than $20 per barrel~~Ms. As ~~described in Note 7, the Company is required to meet certain financial and non-financial covenants as a condition to its credit facilities. Under the Company~~Buie’s ~~second~~extensive ~~lien~~upstream ~~term~~and ~~loan~~executive ~~(“Term~~management ~~Loan”),~~experience ~~the~~makes ~~Company~~her isqualified ~~required~~ to ~~maintain~~serve ~~an Asset Coverage Ratio of not less than 1.5 to 1.0, which is calculated~~ as ~~the~~a ~~value~~director of ~~its Total Proved Reserves (PV 9%) based upon~~ the ~~forward month prices quoted on the NYMEX, adjusted for basis differentials or premiums and transportation costs and to reflect the~~ Company~~’s commodity hedging agreements then in effect to Total Debt~~. The value of the Company’s oil and gas reserves, (including “Total Proved Reserves” as described in the Term Loan agreement) is highly sensitive to future commodity prices. The Company regularly enters into commodity derivative contracts to protect the cash flows associated with the Company’s proved developed producing wells and to provide supplemental liquidity to mitigate decreases in revenue due to reductions in commodity prices.

Based on the Company’s historical experience, in periods of sustained low commodity prices, the prevailing market price for oil and gas services has also decreased, including the types of costs included in the Company’s lease operating expenses, drilling costs, completion costs and costs to equip its wells. Subsequent to December 31, 2019, the Company renegotiated pricing with a number of its vendors and entered into contractual arrangements with drilling and completion service providers at reduced costs relative to the assumed costs in the Company’s year-end reserve report. Additionally, the Company has changed its field operating procedures in response to the material drop in oil prices which further reduces its cost structure relative to that assumed in the Company’s year-end reserve report. The Company continues to work to secure additional costs reductions.

~~Commodity~~Damien ~~hedging~~A. ~~that~~Hannes ~~the~~has ~~Company~~been ~~currently~~a Director since August 2009. Mr. Hannes has inover ~~place,~~25 ~~combined~~years ~~with~~of ~~cost~~finance, ~~reductions~~operations, ~~are~~sales ~~expected~~and tomanagement ~~reduce~~experience. ~~the~~He ~~impact~~has ofmost ~~recent~~recently ~~commodity~~served ~~price~~over ~~declines. However,~~15 ~~given~~years ~~the~~as ~~recent~~a ~~decline~~managing director and ~~continued~~a ~~volatility~~member of ~~commodity~~the ~~prices~~operating committee, ~~the~~among ~~Company~~other ~~cannot~~senior ~~assert~~management ~~that~~positions, itfor isCredit ~~probable~~Suisse’s ~~that~~listed itderivatives ~~will~~business ~~comply~~in ~~with~~equities, ~~the~~commodities ~~Asset~~and ~~Coverage~~fixed ~~Ratio~~income in its Asia and ~~other~~Pacific ~~covenants~~region. ~~within~~From ~~the~~1986 ~~next~~to 121993, ~~months~~Mr. ~~following~~Hannes ~~the~~was ~~date~~a ofdirector ~~this~~for ~~report. A~~Fay ~~breach~~Richwhite ofAustralia, ~~any~~a ~~covenant~~New inZealand ~~Company’s~~merchant ~~credit~~bank. ~~agreements~~Prior ~~will~~to ~~result~~his intenure ~~default~~with ~~under~~Fay ~~both~~Richwhite, Mr. Hannes was the ~~Company’s~~director ~~Term~~of ~~Loan~~operations and ~~cross~~chief ~~default~~financial onofficer ~~the~~of ~~Company’s~~Donaldson, ~~revolving~~Lufkin ~~credit~~and ~~facility~~Jenrette Futures Ltd, ~~after~~a ~~any~~U.S. ~~applicable~~investment ~~grace~~bank. ~~period~~He has successfully raised capital and developed and managed mining, ~~which~~commodities ~~could~~trading ~~result~~and manufacturing businesses in ~~acceleration~~the global market. He holds a Bachelor of Business degree from the ~~amounts~~NSW ~~outstanding~~University ~~under~~of Technology in Australia and subsequently completed the ~~credit~~Institute ~~facilities~~of byChartered Accounts Professional Year before being seconded into the ~~Company’s~~commercial ~~lenders~~sector.

Additionally, the Company’s credit facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception. The issuance of these consolidated financial statements with the accompanying audit opinion constitutes a default under the senior secured revolving credit facility (“Revolving Facility”) and Term Loan. The Company obtained waivers from its Revolving Facility and Term Loan lenders, executed on May 8, 2020 and May 11, 2020, respectively, to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and other related defaults. These waivers were effective April 29, 2020, subject to the conditions set forth in the waivers. As described in Note 15, in consideration for the waiver under our Revolving Facility, the Company agreed to certain limitations on its ability to effect draws under the revolving credit facility until such time as the second quarter 2020 borrowing base redetermination has been completed. In addition, in consideration for waiver with respect to the Term Loan, the Company agreed to amend certain covenants in the Term Loan, as to be mutually agreed with the Term Loan lenders, within 15 days from the execution date. The waiver under our Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion, within 90 days from the execution date. Failure to enter into such amendments with respect to our Term Loan within 15 days (or a similar amendment with respect to our Revolving Facility on the date the Term Loan is amended) would constitute an event of default under the credit facilities, in which case the amounts outstanding under the credit facilities could be accelerated and become immediately due and payable. While management believes that it will finalize such amendments within the required time frame, there can be no assurance that management’s efforts will result in any finalizing these amendments or the ultimate terms of any such amendments.

65 The Board believes that Mr. Hannes’ extensive finance background specific to the oil and gas industry makes him qualified to serve as a director of the Company, as well as an audit committee financial expert under the SEC guidelines.

~~Table of Contents~~

~~Although~~H. ~~the~~Weldon ~~Company~~Holcombe has ~~obtained~~been ~~these~~a ~~waivers~~director since December 2012. Mr. Holcombe has over 30 years of onshore and offshore U.S. oil and gas industry experience, ~~there~~including istechnology, noreservoir ~~guarantee~~engineering, ~~that~~drilling and completions, production operations, construction, field development and optimization, Health, Safety and Environmental (“HSE”), and management of office, field and contract personnel. Most recently, Mr. Holcombe served as the Executive Vice President, Mid Continental Region, for Petrohawk Energy Corporation from 2006 until its ~~lenders~~acquisition ~~will~~by ~~agree~~BHP toBilliton ~~waive~~in ~~events~~2011, after which Mr. Holcombe served as Vice President of ~~default~~New orTechnology ~~potential~~Development ~~events~~for BHP Billiton’s Petroleum Division. In his capacity as Executive Vice President for Petrohawk Energy Corporation, Mr. Holcombe managed development of ~~default~~leading inunconventional resource plays, including the ~~future~~Haynesville, Fayetteville and Permian areas. In ~~the~~addition, ~~event~~Mr. ~~that~~Holcombe ~~some~~served oras ~~all~~President of ~~the~~Big ~~amounts~~Hawk ~~outstanding~~LLC, ~~under~~a ~~its~~subsidiary ~~credit~~of ~~facilities~~Petrohawk ~~are~~Energy ~~accelerated~~Corporation, ~~and~~a ~~become~~provider ~~immediately~~of ~~due~~basic oil and ~~payable~~gas construction, ~~the~~logistics ~~Company~~and ~~does~~rental ~~not~~services. ~~have~~Mr. ~~sufficient~~Holcombe ~~liquidity~~also toserved ~~repay~~as ~~such~~corporate ~~outstanding~~HSE ~~amounts.~~officer ~~These~~for ~~conditions~~Petrohawk and ~~events~~joint ~~raise~~chairperson ~~substantial~~of ~~doubt~~the ~~about~~steering ~~the~~committee ~~entity~~that managed construction and operation of a gathering system in Petrohawk’s ~~ability~~Haynesville field with one billion cubic feet of natural gas production per day capacity. Prior to ~~continue~~Petrohawk, asMr. Holcombe served in a ~~going~~variety ~~concern~~of ~~within~~senior ~~one~~level ~~year~~management, ~~after~~operations ~~the~~and ~~date~~engineering ~~that~~roles for KCS Energy and Exxon. Mr. Holcombe has also provided managerial, operational and technical consulting to various companies operating in the ~~financial~~Haynesville, ~~statements~~Eagle ~~are~~Ford ~~issued~~and Permian basins. Mr. Holcombe holds a Bachelor of Science degree in civil engineering from the University of Auburn.

Management is currently pursuing and evaluating several plans to mitigate the conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern, which include the following:

·The ~~Renegotiating~~Board ~~pricing~~believes ~~with~~that aMr. ~~number~~Holcomb’s ofextensive ~~its~~experience ~~operating expenditure vendors~~ and ~~has~~knowledge ~~realized~~of ~~lower~~oil ~~drilling~~ and ~~completion~~gas ~~costs~~exploration, ongeology, ~~recent~~reservoir ~~development~~engineering, ~~relative~~operations toand ~~the~~management ~~costs~~makes ~~incurred~~him inqualified ~~2019~~to ~~and~~serve ~~the~~as ~~assumed~~a ~~costs~~director inof the Company~~’s year-end reserve report~~.

~~· Negotiating with its lenders to obtain waivers for potential failures in covenants.~~

~~· Pursuing further changes to its cost structure in response to the material drop in oil prices.~~62

·Table ~~Pursuing~~of ~~additional costs savings with its vendors and other internal costs, including a reduction in force, which occurred in early May 2020.~~Contents

~~There~~Neville ~~can~~W. beMartin nohas ~~assurance~~been ~~that~~a ~~sufficient~~Director ~~liquidity~~since ~~can~~January be2012. ~~obtained~~Prior to ~~meet~~his ~~the~~election, ~~outstanding~~he ~~obligations~~was ofan ~~the~~alternate ~~Company,~~director ifon ~~repayment~~our board of ~~its~~directors. ~~credit~~Mr. ~~facilities~~Martin ishas ~~accelerated.~~over As40 years of experience as a ~~result~~lawyer specializing in corporate law and mining, oil and ~~given~~gas ~~the~~law. ~~recent~~He ~~declines~~was ~~and~~formerly ~~continued~~a ~~volatility~~consultant into ~~commodity~~the ~~prices~~Australian law firm, ~~the~~Minter ~~Company~~Ellison. Mr. Martin has ~~concluded~~served ~~that~~as ~~management’s~~a ~~plans~~director doon ~~not~~the ~~alleviate~~boards ~~substantial~~of ~~doubt~~several ~~about~~Australian companies listed on the ~~Company’s~~Australian ~~ability~~Securities Exchange, including Stuart Petroleum Ltd from 1999 to ~~continue~~2002, asAustin Exploration Ltd. from 2005 to 2008 and Adelaide Energy Ltd from 2005 to 2011. Mr. Martin is the former state president of the Australian Resource and Energy Law Association. Mr. Martin holds a ~~going~~Bachelor ~~concern~~of Laws degree from Adelaide University.

The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty.

~~Use~~The Board believes that Mr. Martin’s extensive experience in the oil and gas industry, and his legal experience representing a diverse set of ~~Estimates~~ industry clients, makes him qualified to serve as a director of the Company.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (i) oil and natural gas reserves; (ii) impairment tests of long-lived assets; (iii) depreciation, depletion and amortization; (iv) asset retirement obligations; (v) assignment of fair value and allocation of purchase price in connection with business combinations; (vi) income taxes; (vii) accrued liabilities; (viii) valuation of derivative instruments; and (ix) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates. Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant negative impact to the Company’s business, financial condition, results of operations and cash flows.

~~Cash~~Thomas L. Mitchell has been a director since October 2018. Mr. Mitchell is a strategic finance leader with a record of driving growth in energy business models as the CFO of both large and ~~Cash~~small ~~Equivalents~~ companies in the Oil and Gas Industry. He has had a career of strong Fortune 500 experience with exploration and production companies, and broad energy exposure with offshore drilling and midstream gathering and marketing companies. In his last position as EVP and Chief Financial Officer of Devon Energy Corporation from 2014 to 2017, Mr. Mitchell lead the finance and business development organizations, and also helped the company successfully strengthen its asset quality through strategic acquisitions. Previously, Mr. Mitchell served as EVP and Chief Financial Officer and a member of the board of directors of Midstates Petroleum Company, a private equity-funded exploration and production company. While there, Mr. Mitchell led the initial public offering listing of the company on the New York Stock Exchange in April 2012. From November 2006 to September 2011, Mr. Mitchell was the Senior Vice President, Chief Financial Officer of Noble Corporation, a publicly-held offshore drilling contractor for the oil and gas industry. Following his formal education, Mr. Mitchell began his career in public accounting with Arthur Andersen & Co. where he practiced as a CPA (currently inactive), then, in 1989 entered the oil and gas industry at Apache Corporation where he spent eighteen years in various finance and commercial roles the last being Vice President and Controller. Mr. Mitchell currently serves on the boards of Ring Energy, Inc. (NYSEAMERICAN: REI), a public exploration and production company, and EPIC Midstream Holdings GP, LLC, a private midstream crude and NGL infrastructure company. He also serves on the board of Hines Global REIT, Inc., a public real estate investment trust which is in its final liquidation phase after a successful eleven-year investment life. He previously served on the board of directors of EnLink Midstream Partners, LP and EnLink Midstream, LLC. Mr. Mitchell graduated from Bob Jones University with a B.S. in Accounting.

~~Cash and cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less.~~

66 The Board believes that Mr. Mitchell’s extensive finance, accounting and executive management experience makes him qualified to serve as a director of the Company, as well as an audit committee financial expert under the SEC guidelines.

~~Table of Contents~~

~~Accounts~~Cathy ~~Receivable~~L. ~~Trade~~Anderson has been our Executive Vice President, Chief Financial Officer & Treasurer since December 2011 and ~~Other~~also serves as Executive Vice President, Chief Financial Officer & Treasurer and a director of Sundance Energy, Inc., a Colorado corporation, which is our primary operating subsidiary. Ms. Anderson has over 35 years of experience, primarily in the oil and gas industry, and has extensive experience in budgeting and forecasting, regulatory reporting, corporate controls, and financial analysis and reporting. Prior to joining us in 2011, Ms. Anderson had been a consultant to companies in the oil and gas industry since 2006. Ms. Anderson held various positions, including Chief Financial Officer of Optigas, Inc., a natural gas gathering, processing, and marketing company, from 2005 to 2006 and Vice President of Internal Audit and Consulting for TeleTech Holdings, Inc., a Nasdaq-listed global service firm providing outsourced customer management, from 2002 to 2004. From 1993 to 1999, Ms. Anderson was the Controller and Chief Accounting Officer of NYSE-listed Key Production Company, Inc. (predecessor to Cimarex Energy). She began her career in 1985 with Arthur Andersen, LLP. Ms. Anderson hold a Bachelor of Science in Business Administration with High Honors, emphasis in Accounting, from the University of Montana. She is a certified public accountant.

The Company has letters of credit in place with certain of its purchasers, which the Company could draw upon in the event the purchaser defaults. Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. At December 31, 2019 and 2018, the Company had no allowance for doubtful accounts. At December 31, 2019 and 2018 the accounts receivable trade and other included the following (in thousands): 63

	December 31,
	2019		2018
Oil, natural gas and NGL sales	$	18,211	$	16,408
Joint interest owners		260		584
Commodity hedge contract receivables and other		4,342		4,257
Receivable due from buyer (Dimmit County oil and gas properties)		4,207		—
Total accounts receivable trade and other	$	27,020	$	21,249

Table of Contents

~~Concentration~~Christopher I. Humber was appointed our and our operating subsidiary, Sundance Energy, Inc.’s, Executive Vice President, General Counsel & Secretary in July 2020. Previously, Mr. Humber served as Jagged Peak Energy Inc.’s Executive Vice President, General Counsel & Secretary from August 2016 through the company’s February 2017 initial public offering until the company’s merger with Parsley Energy, Inc. in January 2020. Prior to that, he served as the Executive Vice President, General Counsel & Secretary of ~~Credit~~Bonanza ~~Risk~~ Creek Energy, Inc. from its initial public offering in December 2011 until March 2016. Prior to that, Mr. Humber was a practicing attorney focusing on mergers and acquisitions, corporate finance, and securities matters for public and private companies as a partner with the law firm Kendall, Koenig & Oelsner PC in Denver, Colorado and an associate with the law firms Hogan & Hartson LLP (now Hogan Lovells US LLP) in Denver, Colorado and Arnold & Porter LLP in Washington, D.C. and McLean, Virginia. Mr. Humber graduated with high honors from Emory University School of Law, where he was Editor-in-Chief of the Emory Law Journal, and holds a Bachelor of Arts in Biology from the University of Colorado at Boulder.

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to continuing review.

AsJames ofR. ~~December~~Redfearn 31was appointed as our and our operating subsidiary, ~~2019~~Sundance Energy, Inc.’s, Executive Vice President and Chief Operating Officer in September 2020. Mr. Redfearn brings over 18 years of diverse experience in upstream oil and gas operations to the ~~Company~~Sundance ~~had~~team. Previous ato ~~receivable~~joining ~~from~~Sundance ~~one~~he ~~purchaser~~was the founder and Chief Executive Officer of 3Fearns LLC, a ~~large~~private ~~midstream~~exploration and production company formed in 2018 to drill and ~~production~~acquire ~~purchaser,~~conventional ofassets ~~$13~~in the Arkoma basin.2 ~~million~~Prior to that, ~~accounted~~from ~~for~~2014 ~~73%~~to of2018, ~~total~~he ~~accounts~~was ~~receivable~~the ~~for~~Chief ~~oil~~Executive Officer of Wagon Wheel Exploration, ~~natural~~a ~~gas~~private equity backed exploration and ~~NGL~~production ~~sales~~company focused on the Arkoma and ArkLaTex basins. As ofFrom ~~December~~2005 ~~31,~~until ~~2019~~2012, Mr. Redfearn served as the ~~Company~~Vice ~~has~~President aof ~~long-term~~Drilling ~~contract~~and Completions for Petrohawk Energy overseeing operations in ~~place~~the ~~with~~Cotton ~~this~~Valley, ~~customer~~Haynesville, ~~under~~Fayetteville, ~~which~~Permian and various other Mid-Continent areas until the ~~Company~~acquisition isby ~~subject~~BHP toBilliton. ~~minimum~~He ~~revenue~~began ~~commitments~~his ~~for~~career ~~gathering~~as a Drilling Engineer at Phillips Petroleum Company where he had multiple assignments, ~~processing~~including international, ~~transportation~~deep water, and ~~marketing~~US ~~services~~Land. ~~totaling~~Mr. ~~$54~~Redfearn holds a B.3S. ~~million~~in ~~through~~Petroleum ~~2022~~Engineering from the University of Oklahoma.

~~As of December 31, 2018, the Company had a receivable due from the same customer of $12.1 million that accounted for 74% of total accounts receivable for oil, natural gas and NGL sales.~~

~~The~~SECTION ~~following~~16(A) ~~tables~~BENEFICIAL ~~present~~OWNERSHIP ~~the~~REPORTING ~~percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2019 and 2018:~~ COMPLIANCE

Year Ended December 31, 2019
Purchaser A		60%
Purchaser B		21%
Year Ended December 31, 2018
Purchaser A		34%
Purchaser B		26%
Purchaser C		23%

~~The~~Section ~~Company~~16(a) ~~owns nearly 100%~~ of the ~~working~~Exchange ~~interest~~Act inrequires the ~~majority~~Company’s ofexecutive ~~the~~officers, ~~wells~~directors ~~that~~and itpersons ~~operates;~~who ~~therefore,~~own ~~joint~~more ~~interest~~than ~~billing~~10% ~~receivables,~~of ~~and~~ the ~~related~~Company’s ~~credit~~Common ~~risk,~~Stock isto ~~minimal. Further,~~file ifinitial ~~payment~~reports isof ~~not~~ownership ~~made~~and bychanges ain ~~working~~ownership ~~interest~~with ~~partner,~~ the ~~Company can withhold future payments of revenue to that working interest partner~~SEC.

~~Table~~Additionally, SEC regulations require that the Company identify any individuals for whom one of ~~Contents~~ the referenced reports was not filed on a timely basis during the most recent fiscal year. Based solely on the Company’s review of Forms 3, 4 and 5 furnished to the Company and any amendments thereto, the Company believes that all persons subject to Section 16(a) of the Exchange Act timely filed all reports required pursuant to such section relating to the Company’s Common Stock in 2020.

~~Oil and Gas Properties~~

~~Proved. The~~CORPORATE Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a unit-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful. For the years ended December 31, 2019 and 2018, the Company recorded depletion, depreciation and amortization expense related to proved oil and gas properties of $91.4 million and $62.1 million, respectively. GOVERNANCE

The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows of the assets to the assets’ net book value. If the net book value exceeds future net cash flows, then the cost of the property is written down to fair value. Fair value for oil and gas properties is generally determined based on discounted future net cash flows. There was no impairment expense during the years ended December 31, 2019 or 2018.

Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized in results of operations. General

~~For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Interest is capitalized until the asset is ready for service.~~

~~Unproved. Unproved~~The ~~properties~~Board ~~consist~~has adopted a Code of ~~costs~~Ethics toand ~~acquire~~Business ~~undeveloped~~Conduct ~~leases~~and ascharters ~~well~~for asour ~~purchases~~Audit ofCommittee, ~~unproved~~Compensation ~~reserves. Capitalized~~Committee, ~~costs~~Nominating ofand ~~unproved~~Corporate ~~property~~Governance ~~are~~Committee, ~~transferred~~and Reserves Committee to ~~proved~~assist ~~property~~the ~~when~~Board ~~related~~in ~~proved~~the ~~reserves~~exercise ~~are~~of ~~determined~~its responsibilities and ~~depleted~~to onserve as a ~~unit-~~framework for the effective governance of~~-production~~ ~~basis. The~~the Company. ~~evaluates~~You ~~significant~~can ~~unproved~~access ~~properties~~our ~~for~~current ~~impairment~~committee ~~based~~charters onand ~~remaining~~our ~~lease~~Code ~~term,~~of ~~drilling~~Ethics ~~results,~~and ~~reservoir~~Business ~~performance,~~Conduct ~~seismic~~in ~~interpretation~~the or“Corporate ~~future~~Governance” ~~plans~~section toof ~~develop~~the ~~acreage~~“About” page of our website located at www. ~~There~~sundanceenergy.net, ~~was~~or noby ~~unproved~~writing ~~property~~to ~~impairment~~Investor ~~expense~~Relations ~~during~~at ~~the~~our ~~years~~offices ~~ended~~at ~~December~~1050 3117th Street, ~~2019~~Suite ~~and~~700, ~~2018~~Denver, Colorado 80265.

Exploratory. Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage, are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining developmental well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.

Filing Compare · Sundance Energy Inc.