false--12-31FY2019000172552629121662968497000.0014000000002124771012136695970P1YP3YP3Y00 0001725526 2019-01-01 2019-12-31 0001725526 2019-06-30 0001725526 2020-02-04 0001725526 2018-12-31 0001725526 2019-12-31 0001725526 2017-01-01 2017-12-31 0001725526 2018-01-01 2018-12-31 0001725526 us-gaap:ProductAndServiceOtherMember 2018-01-01 2018-12-31 0001725526 us-gaap:ProductAndServiceOtherMember 2017-01-01 2017-12-31 0001725526 us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember 2019-01-01 2019-12-31 0001725526 us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember 2018-01-01 2018-12-31 0001725526 us-gaap:OilAndGasMember 2019-01-01 2019-12-31 0001725526 us-gaap:ProductAndServiceOtherMember 2019-01-01 2019-12-31 0001725526 us-gaap:OilAndGasServiceMember 2017-01-01 2017-12-31 0001725526 us-gaap:OilAndGasServiceMember 2019-01-01 2019-12-31 0001725526 us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember 2017-01-01 2017-12-31 0001725526 us-gaap:OilAndGasServiceMember 2018-01-01 2018-12-31 0001725526 us-gaap:OilAndGasMember 2017-01-01 2017-12-31 0001725526 us-gaap:OilAndGasMember 2018-01-01 2018-12-31 0001725526 2017-12-31 0001725526 2016-12-31 0001725526 2017-01-01 0001725526 us-gaap:CommonStockMember 2018-12-31 0001725526 us-gaap:RetainedEarningsMember 2017-12-31 0001725526 us-gaap:AdditionalPaidInCapitalMember 2018-01-01 2018-12-31 0001725526 us-gaap:TreasuryStockMember 2019-12-31 0001725526 us-gaap:AdditionalPaidInCapitalMember 2019-12-31 0001725526 us-gaap:AdditionalPaidInCapitalMember 2017-01-01 0001725526 us-gaap:TreasuryStockMember 2017-01-01 0001725526 us-gaap:CommonStockMember 2017-01-01 2017-12-31 0001725526 us-gaap:CommonStockMember 2016-12-31 0001725526 us-gaap:RetainedEarningsMember 2018-01-01 2018-12-31 0001725526 us-gaap:AdditionalPaidInCapitalMember 2017-01-01 2017-12-31 0001725526 us-gaap:CommonStockMember 2019-12-31 0001725526 us-gaap:TreasuryStockMember 2018-01-01 2018-12-31 0001725526 us-gaap:AdditionalPaidInCapitalMember 2017-12-31 0001725526 us-gaap:RetainedEarningsMember 2018-12-31 0001725526 us-gaap:TreasuryStockMember 2017-01-01 2017-12-31 0001725526 us-gaap:CommonStockMember 2019-01-01 2019-12-31 0001725526 us-gaap:AdditionalPaidInCapitalMember 2018-12-31 0001725526 us-gaap:TreasuryStockMember 2016-12-31 0001725526 us-gaap:AdditionalPaidInCapitalMember 2019-01-01 2019-12-31 0001725526 us-gaap:TreasuryStockMember 2017-12-31 0001725526 us-gaap:RetainedEarningsMember 2017-01-01 2017-12-31 0001725526 us-gaap:TreasuryStockMember 2018-12-31 0001725526 us-gaap:CommonStockMember 2017-12-31 0001725526 us-gaap:RetainedEarningsMember 2019-01-01 2019-12-31 0001725526 us-gaap:CommonStockMember 2018-01-01 2018-12-31 0001725526 us-gaap:TreasuryStockMember 2019-01-01 2019-12-31 0001725526 us-gaap:RetainedEarningsMember 2016-12-31 0001725526 us-gaap:RetainedEarningsMember 2019-12-31 0001725526 us-gaap:AdditionalPaidInCapitalMember 2016-12-31 0001725526 us-gaap:CommonStockMember 2017-01-01 0001725526 us-gaap:RetainedEarningsMember 2017-01-01 0001725526 srt:MaximumMember 2019-01-01 2019-12-31 0001725526 2019-01-01 0001725526 srt:MinimumMember 2019-01-01 2019-12-31 0001725526 hpr:DJBasinNonCoreMember 2017-01-01 2017-12-31 0001725526 hpr:UintaBasinMember 2017-01-01 2017-12-31 0001725526 hpr:PiceanceMember 2017-01-01 2017-12-31 0001725526 us-gaap:CorporateJointVentureMember 2018-12-31 0001725526 hpr:OtherReceivablesMember 2018-12-31 0001725526 us-gaap:CorporateJointVentureMember 2019-12-31 0001725526 hpr:AccruedOilAndNaturalGasSaleMember 2019-12-31 0001725526 hpr:OtherReceivablesMember 2019-12-31 0001725526 hpr:AccruedOilAndNaturalGasSaleMember 2018-12-31 0001725526 hpr:FifthCreekMember 2018-03-19 0001725526 hpr:FifthCreekMember 2018-03-19 2018-03-19 0001725526 hpr:FifthCreekMember 2018-01-01 2018-12-31 0001725526 hpr:FifthCreekMember us-gaap:AcquisitionRelatedCostsMember 2017-01-01 2017-12-31 0001725526 hpr:UintaBasinMember 2017-01-01 2017-12-31 0001725526 hpr:UintaBasinMember 2018-01-01 2018-12-31 0001725526 us-gaap:FairValueInputsLevel3Member 2017-01-01 2017-12-31 0001725526 hpr:FifthCreekMember us-gaap:AcquisitionRelatedCostsMember 2018-01-01 2018-12-31 0001725526 hpr:DJBasinNonCoreMember 2019-01-01 2019-12-31 0001725526 hpr:UintaBasinMember 2017-12-31 0001725526 hpr:ProvedOilAndGasPropertiesMember 2017-01-01 2017-12-31 0001725526 hpr:UnprovedOilAndGasPropertiesMember 2017-01-01 2017-12-31 0001725526 hpr:AmendedCreditFacilityMember 2018-12-31 0001725526 hpr:EightPointSevenFivePercentageSeniorNotesMember 2018-12-31 0001725526 hpr:FinancingObligationsAndOtherMember 2019-12-31 0001725526 hpr:AmendedCreditFacilityMember 2019-12-31 0001725526 hpr:EightPointSevenFivePercentageSeniorNotesMember 2019-12-31 0001725526 hpr:SevenPointZeroPercentageSeniorNotesMember 2018-12-31 0001725526 hpr:CurrentPortionOfLongTermDebtMember 2019-12-31 0001725526 hpr:CurrentPortionOfLongTermDebtMember 2018-12-31 0001725526 hpr:SevenPointZeroPercentageSeniorNotesMember 2019-12-31 0001725526 us-gaap:LongTermDebtMember 2019-12-31 0001725526 us-gaap:LongTermDebtMember 2018-12-31 0001725526 hpr:FinancingObligationsAndOtherMember 2018-12-31 0001725526 hpr:AmendedCreditFacilityMember 2018-01-01 2018-12-31 0001725526 srt:MaximumMember 2019-12-31 0001725526 hpr:EightPointSevenFivePercentageSeniorNotesMember hpr:A2021Member 2019-01-01 2019-12-31 0001725526 hpr:SevenPointSixTwoFivePercentageSeniorNotesMember 2017-01-01 2017-12-31 0001725526 hpr:EightPointSevenFivePercentageSeniorNotesMember hpr:A2023Member 2019-01-01 2019-12-31 0001725526 hpr:EightPointSevenFivePercentageSeniorNotesMember hpr:PriortoJune152020Member 2019-01-01 2019-12-31 0001725526 hpr:EightPointSevenFivePercentageSeniorNotesMember hpr:A2022Member 2019-01-01 2019-12-31 0001725526 2019-02-10 0001725526 hpr:SevenPointZeroPercentageSeniorNotesMember hpr:A2019Member 2019-01-01 2019-12-31 0001725526 hpr:EightPointSevenFivePercentageSeniorNotesMember hpr:A2020Member 2019-01-01 2019-12-31 0001725526 hpr:AmendedCreditFacilityMember 2019-01-01 2019-12-31 0001725526 srt:MinimumMember 2019-12-31 0001725526 hpr:SevenPointZeroPercentageSeniorNotesMember hpr:A2020Member 2019-01-01 2019-12-31 0001725526 2018-03-19 0001725526 us-gaap:CommodityContractMember us-gaap:FairValueInputsLevel1Member 2018-12-31 0001725526 us-gaap:CommodityContractMember us-gaap:FairValueInputsLevel2Member 2019-12-31 0001725526 us-gaap:CommodityContractMember us-gaap:FairValueInputsLevel3Member 2018-12-31 0001725526 us-gaap:MoneyMarketFundsMember us-gaap:FairValueInputsLevel1Member 2019-12-31 0001725526 us-gaap:FairValueInputsLevel2Member 2018-12-31 0001725526 us-gaap:CommodityContractMember 2019-12-31 0001725526 us-gaap:MoneyMarketFundsMember us-gaap:FairValueInputsLevel3Member 2019-12-31 0001725526 us-gaap:FairValueInputsLevel3Member 2019-12-31 0001725526 us-gaap:FairValueInputsLevel2Member 2019-12-31 0001725526 us-gaap:CommodityContractMember us-gaap:FairValueInputsLevel3Member 2019-12-31 0001725526 us-gaap:FairValueInputsLevel3Member 2018-12-31 0001725526 us-gaap:MoneyMarketFundsMember us-gaap:EstimateOfFairValueFairValueDisclosureMember 2019-12-31 0001725526 us-gaap:MoneyMarketFundsMember us-gaap:FairValueInputsLevel2Member 2018-12-31 0001725526 us-gaap:MoneyMarketFundsMember us-gaap:EstimateOfFairValueFairValueDisclosureMember 2018-12-31 0001725526 us-gaap:FairValueInputsLevel1Member 2018-12-31 0001725526 us-gaap:MoneyMarketFundsMember us-gaap:FairValueInputsLevel3Member 2018-12-31 0001725526 us-gaap:MoneyMarketFundsMember us-gaap:FairValueInputsLevel2Member 2019-12-31 0001725526 us-gaap:CommodityContractMember 2018-12-31 0001725526 us-gaap:FairValueInputsLevel1Member 2019-12-31 0001725526 us-gaap:CommodityContractMember us-gaap:FairValueInputsLevel2Member 2018-12-31 0001725526 us-gaap:CommodityContractMember us-gaap:FairValueInputsLevel1Member 2019-12-31 0001725526 us-gaap:MoneyMarketFundsMember us-gaap:FairValueInputsLevel1Member 2018-12-31 0001725526 hpr:DerivativeLiabilitiesMember 2019-12-31 0001725526 hpr:DerivativeAndOtherNonCurrentAssetsMember 2019-12-31 0001725526 hpr:DerivativeAssetsMember 2019-12-31 0001725526 hpr:DerivativeAssetsMember 2018-12-31 0001725526 hpr:DerivativeLiabilitiesMember 2018-12-31 0001725526 hpr:DerivativeAndOtherNonCurrentAssetsMember 2018-12-31 0001725526 hpr:DerivativeAndOtherNonCurrentLiabilitiesMember 2019-12-31 0001725526 hpr:DerivativeAndOtherNonCurrentLiabilitiesMember 2018-12-31 0001725526 hpr:HedgePeriodEndingNextYearMember 2019-12-31 0001725526 hpr:HedgePeriodEndingInTwoYearsMember 2019-12-31 0001725526 hpr:FifthCreekMember 2018-12-31 0001725526 us-gaap:DomesticCountryMember 2018-01-01 2018-12-31 0001725526 us-gaap:StateAndLocalJurisdictionMember 2018-01-01 2018-12-31 0001725526 hpr:NonvestedEquitySharesMember 2019-01-01 2019-12-31 0001725526 hpr:NonvestedPerformanceCashUnitsMember 2019-01-01 2019-12-31 0001725526 hpr:NonvestedPerformanceBasedEquitySharesMember 2019-01-01 2019-12-31 0001725526 us-gaap:DirectorMember 2019-01-01 2019-12-31 0001725526 hpr:SevenPointZeroPercentageSeniorNotesMember 2017-12-31 0001725526 hpr:MergerMember 2017-12-31 0001725526 hpr:EquityOfferingMember 2019-12-31 0001725526 hpr:MergerMember 2019-12-31 0001725526 hpr:EquityOfferingMember 2017-12-31 0001725526 hpr:EquityOfferingMember 2018-12-31 0001725526 hpr:MergerMember 2018-12-31 0001725526 hpr:EquityOfferingMember 2017-01-01 2017-12-31 0001725526 hpr:SevenPointZeroPercentageSeniorNotesMember 2017-01-01 2017-12-31 0001725526 hpr:NonvestedEquityCommonStockUnitsMember 2017-01-01 2017-12-31 0001725526 hpr:NonvestedEquitySharesMember 2017-01-01 2017-12-31 0001725526 hpr:NonvestedEquitySharesMember 2018-01-01 2018-12-31 0001725526 hpr:NonvestedPerformanceBasedEquitySharesMember 2018-01-01 2018-12-31 0001725526 hpr:NonvestedPerformanceCashUnitsMember 2017-01-01 2017-12-31 0001725526 hpr:NonvestedEquityCommonStockUnitsMember 2018-01-01 2018-12-31 0001725526 hpr:NonvestedPerformanceCashUnitsMember 2018-01-01 2018-12-31 0001725526 hpr:NonvestedPerformanceBasedEquitySharesMember 2017-01-01 2017-12-31 0001725526 hpr:NonvestedEquityCommonStockUnitsMember 2019-01-01 2019-12-31 0001725526 us-gaap:DirectorMember 2017-12-31 0001725526 us-gaap:DirectorMember 2018-12-31 0001725526 us-gaap:DirectorMember 2017-01-01 2017-12-31 0001725526 us-gaap:DirectorMember 2018-01-01 2018-12-31 0001725526 us-gaap:DirectorMember 2016-12-31 0001725526 us-gaap:DirectorMember 2019-12-31 0001725526 hpr:TwoThousandEighteenPerformanceProgramMember 2019-01-01 2019-12-31 0001725526 hpr:NonvestedEquitySharesMember 2019-12-31 0001725526 srt:MaximumMember hpr:TwoThousandAndFifteenPerformanceProgramMember 2019-12-31 0001725526 hpr:TwoThousandAndSixteenPerformanceProgramMember 2018-01-01 2018-12-31 0001725526 hpr:NonvestedPerformanceCashUnitsMember 2017-12-31 0001725526 hpr:TwoThousandNineteenPerformanceProgramDomain 2019-01-01 2019-12-31 0001725526 hpr:TwoThousandAndFifteenPerformanceProgramMember 2018-01-01 2018-12-31 0001725526 hpr:TwoThousandAndFourteenPerformanceProgramMember 2019-01-01 2019-12-31 0001725526 hpr:TwoThousandNineteenPerformanceProgramDomain 2019-12-31 0001725526 hpr:TwoThousandAndFourteenPerformanceProgramMember 2017-01-01 2017-12-31 0001725526 srt:MinimumMember hpr:TwoThousandAndFifteenPerformanceProgramMember 2019-12-31 0001725526 hpr:TwoThousandEighteenPerformanceProgramMember hpr:RelativeTSRMember 2019-01-01 2019-12-31 0001725526 hpr:NonvestedPerformanceBasedEquitySharesMember 2017-12-31 0001725526 srt:MaximumMember hpr:TwoThousandAndFourteenPerformanceProgramMember 2019-12-31 0001725526 hpr:TwoThousandEighteenPerformanceProgramMember 2019-12-31 0001725526 hpr:TwoThousandAndFifteenPerformanceProgramMember 2015-01-01 2015-12-31 0001725526 srt:MaximumMember hpr:TwoThousandEighteenPerformanceProgramMember hpr:AbsolutePerformanceandRelativeTSRMember 2019-01-01 2019-12-31 0001725526 hpr:TwoThousandTwelveStockIncentivePlanMember 2019-12-31 0001725526 hpr:TwoThousandAndSeventeenPerformanceProgramDomain 2018-01-01 2018-12-31 0001725526 srt:MaximumMember hpr:TwoThousandAndFifteenPerformanceProgramMember 2019-01-01 2019-12-31 0001725526 hpr:NonvestedEquitySharesMember 2017-12-31 0001725526 hpr:NonvestedPerformanceCashUnitsMember 2018-12-31 0001725526 hpr:NonvestedPerformanceCashUnitsMember 2019-12-31 0001725526 hpr:TwoThousandEighteenPerformanceProgramMember hpr:AbsolutePerformanceMember 2019-01-01 2019-12-31 0001725526 hpr:NonvestedPerformanceBasedEquitySharesMember hpr:TwoThousandAndFourteenPerformanceProgramMember 2014-01-01 2014-12-31 0001725526 srt:MaximumMember hpr:TwoThousandAndFourteenPerformanceProgramMember 2019-01-01 2019-12-31 0001725526 hpr:TwoThousandAndFifteenPerformanceProgramMember 2019-01-01 2019-12-31 0001725526 hpr:NonvestedEquitySharesMember 2018-12-31 0001725526 hpr:NonvestedPerformanceBasedEquitySharesMember 2019-12-31 0001725526 srt:MaximumMember hpr:TwoThousandNineteenPerformanceProgramDomain hpr:AbsolutePerformanceandRelativeTSRMember 2019-01-01 2019-12-31 0001725526 hpr:NonvestedPerformanceCashUnitsMember 2016-12-31 0001725526 hpr:NonvestedPerformanceBasedEquitySharesMember 2018-12-31 0001725526 hpr:NonvestedPerformanceBasedEquitySharesMember 2016-12-31 0001725526 hpr:NonvestedEquitySharesMember 2016-12-31 0001725526 us-gaap:SalesRevenueProductLineMember us-gaap:CustomerConcentrationRiskMember 2018-01-01 2018-12-31 0001725526 us-gaap:SalesRevenueProductLineMember us-gaap:CustomerConcentrationRiskMember 2019-01-01 2019-12-31 0001725526 us-gaap:SalesRevenueProductLineMember us-gaap:CustomerConcentrationRiskMember 2017-01-01 2017-12-31 0001725526 hpr:ParentIssuerMember srt:ReportableLegalEntitiesMember 2017-01-01 2017-12-31 0001725526 srt:GuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2017-01-01 2017-12-31 0001725526 srt:ConsolidationEliminationsMember 2017-01-01 2017-12-31 0001725526 srt:ParentCompanyMember srt:ReportableLegalEntitiesMember 2018-12-31 0001725526 srt:ConsolidationEliminationsMember 2018-12-31 0001725526 srt:SubsidiaryIssuerMember srt:ReportableLegalEntitiesMember 2018-12-31 0001725526 srt:SubsidiaryIssuerMember srt:ReportableLegalEntitiesMember 2018-01-01 2018-12-31 0001725526 srt:ConsolidationEliminationsMember 2018-01-01 2018-12-31 0001725526 srt:ParentCompanyMember srt:ReportableLegalEntitiesMember 2018-01-01 2018-12-31 0001725526 srt:SubsidiaryIssuerMember srt:ReportableLegalEntitiesMember 2017-12-31 0001725526 srt:ConsolidationEliminationsMember 2017-12-31 0001725526 srt:ParentCompanyMember srt:ReportableLegalEntitiesMember 2017-12-31 0001725526 srt:GuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2016-12-31 0001725526 srt:ConsolidationEliminationsMember 2016-12-31 0001725526 srt:GuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2017-12-31 0001725526 hpr:ParentIssuerMember srt:ReportableLegalEntitiesMember 2017-12-31 0001725526 hpr:ParentIssuerMember srt:ReportableLegalEntitiesMember 2016-12-31 0001725526 srt:GuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2019-01-01 2019-12-31 0001725526 srt:ConsolidationEliminationsMember 2019-01-01 2019-12-31 0001725526 srt:SubsidiaryIssuerMember srt:ReportableLegalEntitiesMember 2019-01-01 2019-12-31 0001725526 srt:ParentCompanyMember srt:ReportableLegalEntitiesMember 2019-01-01 2019-12-31 0001725526 srt:SubsidiaryIssuerMember srt:ReportableLegalEntitiesMember 2019-12-31 0001725526 srt:ParentCompanyMember srt:ReportableLegalEntitiesMember 2019-12-31 0001725526 srt:GuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2019-12-31 0001725526 srt:GuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2018-12-31 0001725526 srt:ConsolidationEliminationsMember 2019-12-31 iso4217:USD xbrli:shares iso4217:USD xbrli:shares xbrli:pure utreg:bbl hpr:counterparty hpr:integer hpr:unit hpr:age hpr:Customer

false2020FY0001725526December 31P3YP1YP3YP3YP1Yus-gaap:AccountsPayableAndAccruedLiabilitiesMemberus-gaap:AccountsPayableAndAccruedLiabilitiesMemberus-gaap:OtherNoncurrentLiabilitiesMemberus-gaap:OtherNoncurrentLiabilitiesMember00017255262020-01-012020-12-31iso4217:USD00017255262020-06-30xbrli:shares00017255262021-02-0400017255262020-12-3100017255262019-12-31iso4217:USDxbrli:shares0001725526us-gaap:OilAndGasMember2020-01-012020-12-310001725526us-gaap:OilAndGasMember2019-01-012019-12-310001725526us-gaap:OilAndGasMember2018-01-012018-12-310001725526us-gaap:ProductAndServiceOtherMember2020-01-012020-12-310001725526us-gaap:ProductAndServiceOtherMember2019-01-012019-12-310001725526us-gaap:ProductAndServiceOtherMember2018-01-012018-12-3100017255262019-01-012019-12-3100017255262018-01-012018-12-310001725526us-gaap:OilAndGasServiceMember2020-01-012020-12-310001725526us-gaap:OilAndGasServiceMember2019-01-012019-12-310001725526us-gaap:OilAndGasServiceMember2018-01-012018-12-310001725526us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember2020-01-012020-12-310001725526us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember2019-01-012019-12-310001725526us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember2018-01-012018-12-3100017255262018-12-3100017255262017-12-310001725526us-gaap:CommonStockMember2017-12-310001725526us-gaap:AdditionalPaidInCapitalMember2017-12-310001725526us-gaap:RetainedEarningsMember2017-12-310001725526us-gaap:TreasuryStockMember2017-12-310001725526us-gaap:CommonStockMember2018-01-012018-12-310001725526us-gaap:AdditionalPaidInCapitalMember2018-01-012018-12-310001725526us-gaap:TreasuryStockMember2018-01-012018-12-310001725526us-gaap:RetainedEarningsMember2018-01-012018-12-310001725526us-gaap:CommonStockMember2018-12-310001725526us-gaap:AdditionalPaidInCapitalMember2018-12-310001725526us-gaap:RetainedEarningsMember2018-12-310001725526us-gaap:TreasuryStockMember2018-12-310001725526us-gaap:CommonStockMember2019-01-012019-12-310001725526us-gaap:AdditionalPaidInCapitalMember2019-01-012019-12-310001725526us-gaap:TreasuryStockMember2019-01-012019-12-310001725526us-gaap:RetainedEarningsMember2019-01-012019-12-310001725526us-gaap:CommonStockMember2019-12-310001725526us-gaap:AdditionalPaidInCapitalMember2019-12-310001725526us-gaap:RetainedEarningsMember2019-12-310001725526us-gaap:TreasuryStockMember2019-12-310001725526us-gaap:CommonStockMember2020-01-012020-12-310001725526us-gaap:AdditionalPaidInCapitalMember2020-01-012020-12-310001725526us-gaap:TreasuryStockMember2020-01-012020-12-310001725526us-gaap:RetainedEarningsMember2020-01-012020-12-310001725526us-gaap:CommonStockMember2020-12-310001725526us-gaap:AdditionalPaidInCapitalMember2020-12-310001725526us-gaap:RetainedEarningsMember2020-12-310001725526us-gaap:TreasuryStockMember2020-12-310001725526hpr:AmendedCreditFacilityMember2019-12-310001725526hpr:AmendedCreditFacilityMember2020-12-310001725526us-gaap:SeniorNotesMember2020-12-310001725526hpr:AccruedOilAndNaturalGasSaleMember2020-12-310001725526hpr:AccruedOilAndNaturalGasSaleMember2019-12-310001725526us-gaap:CorporateJointVentureMember2020-12-310001725526us-gaap:CorporateJointVentureMember2019-12-310001725526hpr:OtherReceivablesMember2020-12-310001725526hpr:OtherReceivablesMember2019-12-310001725526hpr:ProvedOilAndGasPropertiesMember2020-01-012020-12-310001725526hpr:ProvedOilAndGasPropertiesMember2019-01-012019-12-310001725526hpr:ProvedOilAndGasPropertiesMember2018-01-012018-12-310001725526hpr:UnprovedOilAndGasPropertiesMember2020-01-012020-12-310001725526hpr:UnprovedOilAndGasPropertiesMember2019-01-012019-12-310001725526hpr:UnprovedOilAndGasPropertiesMember2018-01-012018-12-310001725526hpr:UnprovedOilAndGasPropertiesMember2020-01-012020-03-310001725526hpr:UnprovedOilAndGasPropertiesMember2020-10-012020-12-310001725526srt:MinimumMember2020-01-012020-12-310001725526srt:MaximumMember2020-01-012020-12-3100017255262019-01-010001725526hpr:DJBasinNonCoreMember2019-01-012019-12-310001725526hpr:FifthCreekMember2018-03-192018-03-190001725526hpr:FifthCreekMember2018-03-190001725526hpr:FifthCreekMember2018-01-012018-12-310001725526us-gaap:AcquisitionRelatedCostsMemberhpr:FifthCreekMember2018-01-012018-12-310001725526hpr:SevenPointZeroPercentageSeniorNotesMember2020-12-310001725526hpr:SevenPointZeroPercentageSeniorNotesMember2019-12-310001725526hpr:EightPointSevenFivePercentageSeniorNotesMember2020-12-310001725526hpr:EightPointSevenFivePercentageSeniorNotesMember2019-12-310001725526hpr:AmendedCreditFacilityMember2020-03-310001725526hpr:AmendedCreditFacilityMember2020-09-300001725526hpr:AmendedCreditFacilityMember2020-01-012020-12-31xbrli:pure0001725526srt:MinimumMember2020-01-012020-03-310001725526srt:MaximumMember2020-01-012020-03-310001725526srt:MinimumMember2020-03-310001725526srt:MaximumMember2020-03-310001725526hpr:SevenPointZeroPercentageSeniorNotesMemberhpr:A2020Member2020-01-012020-12-310001725526hpr:A2020Memberhpr:EightPointSevenFivePercentageSeniorNotesMember2020-01-012020-12-310001725526hpr:A2021Memberhpr:EightPointSevenFivePercentageSeniorNotesMember2020-01-012020-12-310001725526hpr:A2022Memberhpr:EightPointSevenFivePercentageSeniorNotesMember2020-01-012020-12-310001725526hpr:A2023Memberhpr:EightPointSevenFivePercentageSeniorNotesMember2020-01-012020-12-3100017255262018-03-190001725526us-gaap:FairValueInputsLevel1Memberus-gaap:MoneyMarketFundsMember2020-12-310001725526us-gaap:MoneyMarketFundsMemberus-gaap:FairValueInputsLevel2Member2020-12-310001725526us-gaap:FairValueInputsLevel3Memberus-gaap:MoneyMarketFundsMember2020-12-310001725526us-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:MoneyMarketFundsMember2020-12-310001725526us-gaap:FairValueInputsLevel1Member2020-12-310001725526us-gaap:FairValueInputsLevel2Member2020-12-310001725526us-gaap:FairValueInputsLevel3Member2020-12-310001725526us-gaap:FairValueInputsLevel1Memberus-gaap:CommodityContractMember2020-12-310001725526us-gaap:CommodityContractMemberus-gaap:FairValueInputsLevel2Member2020-12-310001725526us-gaap:FairValueInputsLevel3Memberus-gaap:CommodityContractMember2020-12-310001725526us-gaap:CommodityContractMember2020-12-310001725526us-gaap:FairValueInputsLevel1Memberus-gaap:MoneyMarketFundsMember2019-12-310001725526us-gaap:MoneyMarketFundsMemberus-gaap:FairValueInputsLevel2Member2019-12-310001725526us-gaap:FairValueInputsLevel3Memberus-gaap:MoneyMarketFundsMember2019-12-310001725526us-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:MoneyMarketFundsMember2019-12-310001725526us-gaap:FairValueInputsLevel1Member2019-12-310001725526us-gaap:FairValueInputsLevel2Member2019-12-310001725526us-gaap:FairValueInputsLevel3Member2019-12-310001725526us-gaap:FairValueInputsLevel1Memberus-gaap:CommodityContractMember2019-12-310001725526us-gaap:CommodityContractMemberus-gaap:FairValueInputsLevel2Member2019-12-310001725526us-gaap:FairValueInputsLevel3Memberus-gaap:CommodityContractMember2019-12-310001725526us-gaap:CommodityContractMember2019-12-3100017255262020-03-310001725526us-gaap:FairValueInputsLevel3Memberhpr:ProvedOilAndGasPropertiesMember2020-03-310001725526hpr:ProvedOilAndGasPropertiesMember2020-01-012020-03-3100017255262020-01-012020-03-310001725526us-gaap:FairValueInputsLevel3Memberhpr:UnprovedOilAndGasPropertiesMember2020-03-310001725526hpr:DerivativeAssetsMember2020-12-310001725526hpr:DerivativeAndOtherNonCurrentAssetsMember2020-12-310001725526hpr:DerivativeLiabilitiesMember2020-12-310001725526hpr:DerivativeAndOtherNonCurrentLiabilitiesMember2020-12-310001725526hpr:DerivativeAssetsMember2019-12-310001725526hpr:DerivativeAndOtherNonCurrentAssetsMember2019-12-310001725526hpr:DerivativeLiabilitiesMember2019-12-310001725526hpr:DerivativeAndOtherNonCurrentLiabilitiesMember2019-12-31utr:bbl0001725526srt:CrudeOilMemberus-gaap:SwapMemberhpr:HedgePeriodEndingNextYearMember2020-12-31iso4217:USDhpr:unit0001725526hpr:HedgePeriodEndingInTwoYearsMembersrt:CrudeOilMemberus-gaap:SwapMember2020-12-310001725526srt:NaturalGasReservesMemberus-gaap:SwapMemberhpr:HedgePeriodEndingNextYearMember2020-12-310001725526srt:NaturalGasReservesMemberhpr:HedgePeriodEndingInTwoYearsMemberus-gaap:SwapMember2020-12-310001725526hpr:DerivativeRollSwapsMembersrt:CrudeOilMemberhpr:HedgePeriodEndingNextYearMember2020-12-310001725526hpr:HedgePeriodEndingInTwoYearsMemberhpr:DerivativeRollSwapsMembersrt:CrudeOilMember2020-12-310001725526srt:CrudeOilMemberhpr:HedgePeriodEndingNextYearMemberus-gaap:SwaptionMember2020-12-310001725526hpr:HedgePeriodEndingInTwoYearsMembersrt:CrudeOilMemberus-gaap:SwaptionMember2020-12-310001725526srt:NaturalGasPerThousandCubicFeetMemberhpr:HedgePeriodEndingNextYearMemberhpr:CashlessCollarsMember2020-12-31hpr:counterparty0001725526hpr:FifthCreekMember2018-12-310001725526us-gaap:DomesticCountryMember2018-01-012018-12-310001725526us-gaap:StateAndLocalJurisdictionMember2018-01-012018-12-3100017255262017-01-012017-12-310001725526hpr:MergerMember2018-12-310001725526hpr:MergerMember2020-12-310001725526hpr:MergerMember2019-12-310001725526hpr:NonvestedEquitySharesMember2020-01-012020-12-310001725526hpr:NonvestedEquityCommonStockUnitsMember2020-01-012020-12-310001725526hpr:NonvestedPerformanceCashUnitsMember2020-01-012020-12-310001725526hpr:NonvestedEquitySharesMember2019-01-012019-12-310001725526hpr:NonvestedEquitySharesMember2018-01-012018-12-310001725526hpr:NonvestedEquityCommonStockUnitsMember2019-01-012019-12-310001725526hpr:NonvestedEquityCommonStockUnitsMember2018-01-012018-12-310001725526hpr:NonvestedPerformanceCashUnitsMember2019-01-012019-12-310001725526hpr:NonvestedPerformanceCashUnitsMember2018-01-012018-12-310001725526hpr:NonvestedPerformanceCashUnitsMember2020-12-310001725526hpr:NonvestedPerformanceCashUnitsMember2019-12-310001725526hpr:NonvestedPerformanceCashUnitsMember2018-12-310001725526hpr:TwoThousandTwelveStockIncentivePlanMember2020-12-310001725526hpr:NonvestedEquitySharesMember2019-12-310001725526hpr:NonvestedEquitySharesMember2018-12-310001725526hpr:NonvestedEquitySharesMember2017-12-310001725526hpr:NonvestedEquitySharesMember2020-12-310001725526srt:DirectorMember2020-01-012020-12-310001725526srt:DirectorMember2019-12-310001725526srt:DirectorMember2018-12-310001725526srt:DirectorMember2017-12-310001725526srt:DirectorMember2019-01-012019-12-310001725526srt:DirectorMember2018-01-012018-12-310001725526srt:DirectorMember2020-12-310001725526hpr:NonvestedPerformanceCashUnitsMember2017-12-310001725526hpr:TwoThousandAndFifteenPerformanceProgramMember2018-01-012018-12-310001725526hpr:TwoThousandAndSixteenPerformanceProgramMember2018-01-012018-12-31hpr:integer0001725526hpr:TwoThousandAndSeventeenPerformanceProgramDomain2018-01-012018-12-310001725526hpr:TwoThousandAndFifteenPerformanceProgramMember2020-01-012020-12-310001725526hpr:TwoThousandAndFifteenPerformanceProgramMembersrt:MinimumMember2020-12-310001725526srt:MaximumMemberhpr:TwoThousandAndFifteenPerformanceProgramMember2020-12-310001725526srt:MaximumMemberhpr:TwoThousandAndFifteenPerformanceProgramMember2020-01-012020-12-31hpr:unit0001725526hpr:TwoThousandAndFifteenPerformanceProgramMember2015-01-012015-12-31hpr:agehpr:Customer0001725526us-gaap:CustomerConcentrationRiskMemberus-gaap:SalesRevenueProductLineMember2020-01-012020-12-310001725526us-gaap:CustomerConcentrationRiskMemberus-gaap:SalesRevenueProductLineMember2019-01-012019-12-310001725526us-gaap:CustomerConcentrationRiskMemberus-gaap:SalesRevenueProductLineMember2018-01-012018-12-31utr:acre

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~~2020


☐			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 001-38435

HighPoint Resources Corporation

(Exact name of registrant as specified in its charter)


Delaware						82-3620361
(State or other jurisdiction of incorporation or organization)						(IRS Employer Identification No.)

555 17th Street, Suite 3700

Denver, Colorado 80202

(Address of principal executive office, including zip code)

(303) 293-9100

(Registrant'’s telephone number, including area code)

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

Title of each class

Trading symbol

Name of each exchange on which registered

Common Stock, $.001 par value

HPR

New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

☐ Yes ☑ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

☐ Yes ☑ No

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☑ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). þ Yes ☐ No

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

Large accelerated filer ☐ 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act).

☐ Yes ☑ No

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, ~~2019~~2020 was $~~197~~32,~~315~~515,~~478~~387 (based on the closing price of $114.8275 per share as of the last business day of the fiscal quarter ended June 30, ~~2019~~2020).

As of February 4, ~~2020~~2021, the registrant had ~~213~~4,~~669~~305,~~597~~075 outstanding shares of $0.001 per share par value common stock.

DOCUMENTS INCORPORATED BY REFERENCE

The information required in Part III of this Annual Report on Form 10-K iswill ~~incorporated by reference from the registrant's definitive proxy statement for the registrant's Annual Meeting of Stockholders to~~ be ~~held~~included in ~~May~~a ~~2020~~future tofiling bewith ~~filed~~the ~~pursuant~~SEC towithin ~~Regulation 14A no later than~~ 120 days after ~~the~~December 31, ~~end~~2020, ofand ~~the~~is ~~registrant's~~incorporated ~~fiscal~~by ~~year~~reference ~~ended~~in ~~December 31,~~this ~~2019~~report.

Table of Contents

GLOSSARY OF OIL, NATURAL GAS AND NGL TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and gas industry:

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume.

Bcf. Billion cubic feet of natural gas.

Boe. Barrel of oil equivalent, determined by converting gas volumes to barrels of oil equivalent using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Boe/d. Boe per day.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. Refers to installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

COVID-19. A highly transmissible and pathogenic coronavirus.

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

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or Dry well. An exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

EBITDAX. Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses.

EHS. Environmental, Health and Safety.

Environmental Impact Statement. A more detailed study of the potential direct, indirect and cumulative impacts of a federal project that is subject to public review and potential litigation.

EPA. The United States Environmental Protection Agency.

E&P waste. Exploration and production waste, intrinsic to oil and gas drilling and production operations.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

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

Henry Hub. The Erath, LA settlement point price as quoted in Platt'’s Gas Daily.

Horizontal drilling. A drill rig operation of drilling vertically to a defined depth and then mechanically steering the drill bit to drill horizontally within a designated zone typically defined as the prospective pay zone to be completed for oil and or gas.

Hydraulic fracturing. The injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate natural gas and oil production.

Table of Contents

Identified drilling locations. Total gross locations specifically identified and scheduled by management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

MBoe. Thousand barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

Mcf. Thousand cubic feet of natural gas.

MMBbls. Million barrels of crude oil or other liquid hydrocarbons.

MMBoe. Million barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

MMBtu. Million British thermal units.

MMcf. Million cubic feet of natural gas.

Mt. Belvieu. The Mt. Belvieu, TX settlement point price as quoted by Oil Price Information Service.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Net revenue interest. An owner'’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

NGLs. Natural gas liquids.

NWPL. Northwest Pipeline Corporation price as quoted in Platt'’s Inside FERC.

OPEC. Organization of Petroleum Exporting Countries.

Percentage of proceeds contracts. Under percentage of proceeds (POP) contracts, processors receive an agreed upon percentage of the actual proceeds of the sale of the dry natural gas and NGLs.

Play. A term used to describe an accumulation of oil and/or natural gas resources known to exist, or thought to exist based on geotechnical research, over a large area.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Productive well. Producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The quantities of oil, natural gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

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. Proved undeveloped reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at

Table of Contents

on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years of initial booking, unless the specific circumstances justify a longer time. No proved undeveloped reserves can be attributed 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.

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

SEC. U.S. Securities and Exchange Commission.

Standardized Measure. The present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.

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

Working interest. The operating interest that gives the owner of such interest the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner of such interest to pay a share of the costs of drilling and production operations.

WTI. West Texas Intermediate price as quoted on the New York Mercantile Exchange.

WTI Cushing. The West Texas Intermediate price at the Cushing, OK settlement point as quoted by Bloomberg, using crude oil price bulletins.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains "“forward-looking statements"” within the meaning of Section 27A of the Securities Act of 1933, as amended, (the "“Securities Act"”), Section 21E of the Securities Exchange Act of 1934, as amended (the "“Exchange Act"”), and the Private Securities Litigation Reform Act of 1995. Forward-looking statements include statements about our future strategy, plans, estimates, beliefs, timing and expected performance.

All statements in this report, other than statements of historical fact, are forward-looking statements. Forward-looking statements may be found in "“Items 1 and 2. Business and Properties"”, "“Item 1A. Risk Factors"”, "“Item 7. Management'’s Discussion and Analysis of Financial Condition and Results of Operations"” and other sections of this Annual Report on Form 10-K. In some cases, you can identify forward-looking statements by terminology such as "“expect"”, "“seek"”, "“believe"”, "“upside"”, "“will"”, "“may"”, "“expect"”, "“anticipate"”, "“plan"”, "“will be dependent on"”, "“project"”, "“potential"”, "“intend"”, "“could"”, "“should"”, "“estimate"”, "“predict"”, "“pursue"”, "“target"”, "“objective"”, or "“continue"”, the negative of such terms or other comparable terminology.

Forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, ~~the following~~ risks and uncertainties associated with the following:

•a ~~volatility~~potential ofinability to complete, or market ~~prices~~conditions ~~received~~affecting, ~~for~~the ~~oil~~Merger, ~~natural~~the ~~gas~~Exchange Offer and, ~~NGLs~~if applicable, the Prepackaged Plan (as those terms are defined in Items 1 and 2, Business and Properties – Business – Significant Business Developments – Pending Merger with Bonanza Creek Energy, Inc.);

•legislative ~~actual~~or ~~production~~regulatory ~~being~~changes ~~less~~that ~~than~~can ~~estimated~~affect our ability to permit wells and conduct operations, including on federal lands under the new Biden Administration, as well as ballot initiatives seeking excessive setbacks, drilling moratoria or bans on hydraulic fracturing;

•defaults ~~changes~~under inour bank credit facility (“Credit Facility”), and the ~~estimates~~related ofimpact ~~proved~~on ~~reserves~~our ability to continue as a going concern;

•reductions ~~availability~~in ofthe ~~midstream~~borrowing base under our Credit Facility, and ~~downstream~~the ~~markets~~related toimpact ~~sell~~on our ~~products~~ability to continue as a going concern;

•debt ~~reductions~~and inequity ~~the~~market ~~borrowing~~conditions ~~base~~and ~~under~~availability ~~our~~of ~~revolving~~capital, ~~bank~~and ~~credit~~the ~~facility~~related ~~(sometimes~~impact ~~referred~~on our ability to continue as ~~the~~a ~~"Amended~~going ~~Credit Facility")~~concern;

•outbreaks ~~availability~~ of ~~capital~~communicable atdiseases alike ~~reasonable~~COVID-19 ~~cost~~and resulting regulatory and economic consequences;

•the ~~legislative~~ability orand ~~regulatory~~willingness ~~changes~~of ~~that~~OPEC ~~can~~along ~~affect~~with ~~our~~non-OPEC ~~ability~~oil-producing tocountries ~~permit~~(collectively ~~wells~~known ~~and~~as ~~conduct operations~~“OPEC+”), ~~including~~to ~~ballot~~agree ~~initiatives~~to ~~seeking~~and ~~excessive~~maintain ~~setbacks,~~oil ~~drilling~~price ~~moratoria~~and orproduction ~~bans on hydraulic fracturing~~controls;

•volatility ~~availability~~ of ~~third~~market ~~party~~prices ~~goods~~received for oil, natural gas and ~~services~~NGL, atand ~~reasonable~~the ~~rates~~risk of a prolonged period of depressed prices;

•actual ~~liabilities~~production ~~resulting~~being ~~from~~less ~~litigation~~than concerning alleged damages related to environmental issues, pollution, contamination, personal injury, royalties, marketing, title to properties, validity of leases, regulatory penalties or other matters that may not be covered by an effective indemnity or insuranceestimated; ~~and~~

•changes ~~other~~in ~~uncertainties, including~~ the ~~factors~~estimates ~~discussed below and elsewhere in this Annual Report on Form 10-K, particularly in "Item 1A. Risk Factors", all~~ of ~~which~~proved ~~are difficult to predict.~~reserves;

•availability of midstream and downstream markets to sell our products;

•availability of third party goods and services at reasonable rates;

•liabilities resulting from litigation concerning alleged damages related to environmental issues, pollution, contamination, personal injury, royalties, marketing, title to properties, validity of leases, regulatory penalties or other matters that may not be covered by an effective indemnity or insurance; and

•other uncertainties, including the factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in “Item 1A. Risk Factors”, all of which are difficult to predict.

In light of these and other risks, uncertainties and assumptions, anticipated events addressed in forward looking statements may not occur.

The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by our management. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management'’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader that our expectations will be realized or that future forward-looking events and circumstances will occur as anticipated. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to many factors including those listed above and in "“Item 1A. Risk Factors"” and elsewhere in this Annual Report on Form 10-K. All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. Readers should not place undue reliance on these forward-looking statements, which reflect management's views only as of the date hereof. Other than as required under the securities laws, we do not intend, and do not undertake any obligation to, update or revise any forward-looking statements as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

undue reliance on these forward-looking statements, which reflect management’s views only as of the date hereof. Other than as required under the securities laws, we do not intend, and do not undertake any obligation to, update or revise any forward-looking statements as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Table of Contents

PART I

Items 1 and 2. Business and Properties.

BUSINESS

General

HighPoint Resources Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the "“Company"”, "“HighPoint”, “we"”, "“our"” or "“us"”) is an independent oil and gas company engaged in the exploration, development and production of oil, natural gas and natural gas liquids ("“NGLs"”). We became the successor to Bill Barrett Corporation ("“Bill Barrett"”), on March 19, 2018, upon closing of the transactions contemplated by the Agreement and Plan of Merger, dated December 4, 2017 (the "“2018 Merger Agreement"”), pursuant to which Bill Barrett combined with Fifth Creek Energy Operating Company, LLC ("“Fifth Creek"”) (the "“2018 Merger"”). As a result of the 2018 Merger, Bill Barrett became a wholly-owned subsidiary of HighPoint Resources Corporation and subsequently Bill Barrett changed its name to HighPoint Operating Corporation. We currently conduct our activities principally in the Denver Julesburg Basin ("“DJ Basin"”) in Colorado. Except where the context indicates otherwise, references herein to the "“Company"” with respect to periods prior to the completion of the 2018 Merger refer to Bill Barrett and its subsidiaries.

We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.

We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration and development activities meet stakeholders'’ expectations and regulatory requirements.

We maintain a website at the address http://www.hpres.com. No information on our website is incorporated by reference herein or deemed to be part of this Annual Report on Form 10-K. We make available free of charge through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC via EDGAR and posted at http://www.sec.gov. Additionally, our Code of Business Conduct and Ethics, which includes our code of ethics for senior financial management, Corporate Governance Guidelines, Corporate Responsibility Report, and the charters of our Audit Committee, Compensation Committee, Reserves and EHS Committee and Nominating and Corporate Governance Committee, are posted on our website and are available in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our principal office at 555 17th Street, Suite 3700, Denver, Colorado 80202. We intend to disclose on our website any amendments or waivers to our Code of Business Conduct and Ethics that are required to be disclosed pursuant to Item 5.05 of Form 8-K. Our website contains information provided by other sources that we believe are reliable. We cannot assure you that the information obtained from other sources is accurate or complete.

We operate in one industry segment, which is the exploration, development and production of oil and natural gas, and all operations are conducted in the United States. Consequently, we currently report a single reportable segment. See "“Financial Statements"” and the notes to our consolidated financial statements for financial information about this reportable segment.

Significant Business Developments

Pending Merger with Bonanza Creek Energy, Inc.

On November 9, 2020, the Company and Bonanza Creek Energy, Inc., a Delaware corporation (“Bonanza Creek”), entered into a definitive merger agreement (“Merger Agreement”) to effectuate the strategic combination of Bonanza Creek and HighPoint (“Merger”). The transaction has been unanimously approved by the board of directors of each company. Under the terms of the Merger Agreement, Bonanza Creek has commenced a registered offer to exchange HighPoint’s senior unsecured notes (the “HighPoint Notes”) for senior notes and common stock of Bonanza Creek (the “Exchange Offer”). The Exchange Offer is conditioned on a minimum participation condition of not less than 97.5% of the aggregate outstanding principal amount of each series of HighPoint Notes being validly tendered in accordance with the terms of the Exchange Offer prior to the expiration date of the Exchange Offer (the “Minimum Participation Condition”). Based on the number of shares of Bonanza Creek common stock outstanding as of the date of the Merger Agreement, existing holders of Bonanza Creek common stock

Table of Contents

will own approximately 68% of the issued and outstanding shares of the combined company, existing holders of HighPoint common stock will own approximately 1.6% of the combined company and holders of the HighPoint Notes will own approximately 30.4% of the combined company and up to $100 million of senior unsecured notes to be issued by Bonanza Creek in connection with the Exchange Offer. Registration statements on Form S-4 of Bonanza Creek and a merger proxy of HighPoint have been declared effective by the SEC. The Exchange Offer expires on March 11, 2021 (unless extended by HighPoint and Bonanza Creek) and special meetings for Bonanza Creek and HighPoint stockholders will both be held on March 12, 2021 to approve the Merger.

Concurrently with the Exchange Offer, HighPoint is soliciting votes from the holders of the HighPoint Senior Notes to accept or reject a prepackaged plan of reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (the “Court,” and such plan, the “Prepackaged Plan”).

If the Minimum Participation Condition is met, and if certain customary closing conditions are satisfied (including approval by each company’s shareholders), the companies will effect the Exchange Offer and Bonanza Creek will acquire HighPoint at closing through a merger outside of bankruptcy, whereby HighPoint will merge with a wholly owned subsidiary of Bonanza Creek, with HighPoint continuing its existence as the surviving company following the merger and continuing as a wholly owned subsidiary of Bonanza Creek. If the Minimum Participation Condition is not met, HighPoint intends to file voluntary petitions under Chapter 11 with the Court to effectuate the solicited Prepackaged Plan and consummate the transaction. The consummation of the Prepackaged Plan will be subject to confirmation by the Court in addition to other conditions set forth in the Prepackaged Plan, a transaction support agreement and related transaction documents.

The transactions are expected to close in the first quarter of 2021 under the Exchange Offer or in the first or second quarter of 2021 under the Prepackaged Plan. There can be no assurance that the Merger will be consummated or consummated within the expected timeframe.

PROPERTIES

Overview

As of December 31, ~~2019~~2020, we have one key area of production: the DJ Basin.

Our acreage positions in the DJ Basin are predominantly located in Colorado'’s eastern plains ~~and parts of southeastern Wyoming~~.

DJ Basin Key Statistics

• Estimated proved developed reserves as of December 31, ~~2019~~2020 - ~~127~~50.48 MMBoe.

6•Producing wells - We had interests in 566 gross (396.5 net) producing wells as of December 31, 2020, and we serve as operator of 451 gross wells.

~~Table~~•2020 ofnet ~~Contents~~production - 10,953 MBoe.

•Acreage ~~Producing wells~~ - We ~~had~~held ~~interests~~54,722 innet ~~568~~undeveloped ~~gross~~and ~~(377.9~~76,961 net) ~~producing~~developed ~~wells~~acres as of December 31, ~~2019, and we serve as operator of 423 gross wells~~2020.

•Capital ~~2019~~expenditures ~~net~~- ~~production~~Our -capital 12expenditures for 2020 were $97.3 million for participation in the drilling of 31 gross (13.7 net) wells,~~538~~ ~~MBoe~~acquisition of leasehold acres and construction of gathering facilities.

•As ~~Acreage~~of -December 31, We2020, ~~held~~we ~~66,043~~were ~~net~~not ~~undeveloped~~drilling ~~and~~any 76wells,~~544~~ ~~net~~but ~~developed~~were ~~acres~~waiting asto ofcomplete ~~December~~39 ~~31,~~gross ~~2019~~(16.0 net) wells.

•Based ~~Capital~~on ~~expenditures~~our -proved ~~Our~~reserves ~~capital~~as ~~expenditures~~of ~~for~~January ~~2019~~1, ~~were~~2021, ~~$355.0~~we ~~million~~have ~~for~~a ~~participation~~66% inweighted ~~the~~average ~~drilling~~working ofinterest 74in ~~gross~~our ~~(62.3~~producing ~~net)~~ wells, ~~acquisition~~in ofthe ~~leasehold~~DJ ~~acres and construction of gathering facilities~~Basin.

•The AsDJ ofBasin ~~December~~is 31an oil development area where operators are targeting the Niobrara and Codell formations and employing new technologies to optimize oil recoveries and economic returns. The DJ Basin has a low cost structure, ~~2019~~mature infrastructure, westrong ~~were~~production ~~drilling~~efficiencies, 1multiple ~~gross~~producing (1horizons, ~~net)~~multiple ~~well~~service providers, established reserves, and weprospective ~~were~~drilling ~~waiting~~opportunities, towhich ~~complete~~helps 34facilitate ~~gross~~predictable ~~(22.9~~production ~~net)~~and ~~wells~~reserve growth.

•The ~~Based~~DJ onBasin is our ~~proved~~core ~~reserves~~area as of ~~January~~operation; 1,we drilled 31 gross (13.7 net) operated wells and placed 34 gross (25.0 net) operated wells on initial flowback in 2020,. weWe ~~have~~had atwo ~~64%~~rigs ~~weighted~~operating ~~average~~until ~~working~~we ~~interest~~suspended drilling in ~~our~~May ~~producing~~of 2020. Prior to suspending drilling and completion operations, we continued to drill extended reach horizontal wells in the Niobrara and Codell formations across the DJ Basin, continuing to optimize our completion technology.

The DJ Basin is a high growth oil development area where operators are targeting the Niobrara and Codell formations and employing new technologies to optimize oil recoveries and economic returns. We believe that the DJ Basin offers us significant growth opportunities with potential acreage additions to our current leasehold position, possible development of additional formations, increased utilization of extended reach (long lateral) horizontal wells, well completion optimization and ongoing cost reduction.

The DJ Basin is our core area of operation; we drilled 72 gross (62.1 net) operated wells and placed 69 gross (63.1 net) operated wells on initial flowback there in 2019. We had four rigs operating at the beginning of 2019 and decreased the rig count to two during the year. In 2019, we continued to drill extended reach horizontal wells in the Niobrara and Codell formations across the greater Northeast Wattenberg area of the DJ Basin, continuing to optimize our completion technology and establishing a scalable development program. In addition, we focused on the initial development of the Hereford field assets acquired in the Merger. The combination of this development along with nearby competitor activity continued to de-risk our acreage in the two areas.

Our oil production from the DJ Basin is sold at the lease and is either trucked or transported by pipelines to various markets. Our gas production from the DJ Basin is gathered and processed by third parties, and we receive residue gas and NGL revenue under percentage of proceeds or fee-based contracts.

Table of Contents

Oil and Gas Data

Proved Reserves

The following table presents our estimated net proved oil, natural gas and NGL reserves at each of December 31, ~~2019~~2020, ~~2018~~2019 and ~~2017~~2018 based on reserve reports prepared by us and audited by independent third party petroleum engineers. While we are not required by the SEC or accounting regulations or pronouncements to have our reserve estimates independently audited, such an audit is required under our ~~Amended~~ Credit Facility. All of our proved reserves included in our reserve reports are located in North America. Netherland, Sewell & Associates, Inc. ("“NSAI"”) audited all of our reserves estimates at December 31, ~~2019~~2020, ~~2018~~2019 and ~~2017~~2018. NSAI is retained by and reports to the Reserves and EHS Committee of our Board of Directors. When compared on a well-by-well or lease-by-lease basis, some of our internal estimates of net proved reserves are greater and some are less than NSAI'’s estimates. However, in the aggregate, NSAI'’s estimates of total net proved reserves are within 10% of our internal estimates. In addition to a third party audit, our reserves are reviewed by our Reserves and EHS Committee. The Reserves and EHS Committee reviews the final reserves estimates in conjunction with NSAI'’s audit letter and meets with the key representative of NSAI to discuss NSAI'’s review process and findings.


	As of December 31,
Proved Reserves: (1)	2020	2019	2018
Proved Developed Reserves:
Oil (MMBbls)	22.6	25.7	24.5
Natural gas (Bcf)	92.6	89.4	84.0
NGLs (MMBbls)	12.8	11.2	12.9
Total proved developed reserves (MMBoe)	50.8	51.8	51.4
Proved Undeveloped Reserves:
Oil (MMBbls)	—	48.4	34.5
Natural gas (Bcf)	—	91.9	56.3
NGLs (MMBbls)	—	11.9	9.3
Total proved undeveloped reserves (MMBoe) (2)	—	75.6	53.2
Total Proved Reserves (MMBoe)	50.8	127.4	104.6

(1)Our proved reserves were determined in accordance with SEC guidelines, using the average of the prices on the first day of each month in 2020 for natural gas (Henry Hub price) and oil (WTI Cushing price), subject to certain adjustments, or $1.99 per MMBtu of natural gas and $39.54 per barrel of oil, respectively, without giving effect to hedging transactions. The average NGL price per barrel was based on a percentage of the average oil price, subject to certain adjustments. We currently do not include future reclamation costs net of salvage value in the calculation of our proved reserves.

(2)Approximately 51% and 52% of our estimated proved reserves (by volume) were undeveloped for the years ended December 31, 2019 and 2018, respectively.

The data in the above table represent estimates only. Oil, natural gas and NGLs reserves are estimates of accumulations of oil, natural gas and NGLs that cannot be measured exactly. The accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserves estimates may vary from the quantities of oil, natural gas and NGLs that are ultimately recovered. See “Item 1A. Risk Factors”.

Annually, management develops a capital expenditure plan based on the best data available at the time. Our capital expenditure plan incorporates a development plan for converting PUD reserves to proved developed and includes only PUD reserves that we are reasonably certain will be drilled within five years of booking based upon management’s evaluation of a number of qualitative and quantitative factors, including estimated risk-based returns; estimated well density; commodity prices and cost forecasts; recent drilling recompletion or re-stimulation results and well performance; and anticipated availability of services, equipment, supplies and personnel. This process is intended to ensure that PUD reserves are only booked for locations where a final investment decision has been made based on current corporate strategy. In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19. As the virus spread, global economic activity began to slow resulting in a decrease in demand for oil and natural gas. In response, OPEC+ initiated discussions to reduce production to support energy prices. With OPEC+ unable to agree on cuts, energy prices declined sharply during the first half of 2020. While prices partially recovered during the second half of 2020, uncertainties related to the demand for oil and natural gas remain as the COVID-19 pandemic continues to impact the world economy. The impacts of substantially lower oil, natural gas and NGL

Table of Contents

	As of December 31,
Proved Reserves: (1)	2019	2018	2017
Proved Developed Reserves:
Oil (MMBbls)	25.7	24.5	17.4
Natural gas (Bcf)	89.4	84.0	74.5
NGLs (MMBbls)	11.2	12.9	11.7
Total proved developed reserves (MMBoe)	51.8	51.4	41.5
Proved Undeveloped Reserves:
Oil (MMBbls)	48.4	34.5	22.2
Natural gas (Bcf)	91.9	56.3	68.4
NGLs (MMBbls)	11.9	9.3	10.7
Total proved undeveloped reserves (MMBoe) (2)	75.6	53.2	44.3
Total Proved Reserves (MMBoe) (3)	127.4	104.6	85.8

prices on the economics of our existing wells and planned future development were adversely affected, which led to impairments of our proved and unproved oil and gas properties, reductions to our oil and gas reserve quantities and reductions to the borrowing capacity on our Credit Facility. In response to these conditions, we indefinitely suspended our drilling and completion activity starting in May 2020. In addition, in November 2020 we entered into the Merger Agreement with Bonanza Creek, and that agreement restricts our near-term capital spending levels and does not allow for drilling or completion operations. Furthermore, if the Merger does not close as contemplated, we do not have assurance that we will have the capital availability to resume drilling and completion operations. As a result, we have reclassified 65.9 MMboe of PUD reserves to non-proved categories as of December 31, 2020, not because the PUD locations are uneconomic but rather because we may not have the adequate financial capability to develop the PUD reserves within the five year development window.

~~(1)~~The ~~Our~~following ~~proved~~tables ~~reserves~~illustrate ~~were determined in accordance with SEC guidelines, using~~ the ~~average~~history of ~~the~~our ~~prices~~proved onundeveloped ~~the~~reserves ~~first~~from ~~day of each month in 2019 for natural gas (Henry Hub price) and oil (WTI Cushing price)~~December 31, ~~subject~~2018 tothrough ~~certain adjustments~~December 31, or $2.58 per MMBtu of natural gas and $55.85 per barrel of oil, respectively, without giving effect to hedging transactions. The average NGL price per barrel was based on a percentage of the average oil price, subject to certain adjustments. We currently do not include future reclamation costs net of salvage value in the calculation of our proved reserves.2020:

(2) Approximately 59%, 51% and 52% of our estimated proved reserves (by volume) were undeveloped for the years ended December 31, 2019, 2018 and 2017, respectively.


	As of December 31,
Proved Undeveloped Reserves:	2020	2019	2018
	(MMBoe)
Beginning balance	75.6	53.2	44.3
Additions from drilling program (1)(2)	—	32.2	41.3
Acquisitions	—	1.9	5.2
Engineering revisions (3)	(4.0)	0.8	(6.7)
Price revisions	(0.2)	(0.4)	0.2
Converted to proved developed	(5.5)	(12.1)	(21.1)
Sold/ expired/ other (4)(5)	(65.9)	—	(10.0)
Total proved undeveloped reserves	—	75.6	53.2

(31)The ~~Total~~increase in proved undeveloped reserves ~~have~~for ~~been~~the ~~reduced~~year ~~for~~ended ~~the~~December 31, ~~sale~~2019 ofwas ~~non-core~~related ~~oil~~to ~~and~~the ~~gas~~expansion ~~properties~~of our drilling program in the ~~amount~~Hereford offield ~~11.2~~and ~~MMBoe~~a ~~for~~successful ~~the~~extension ~~year~~test ~~ended~~in ~~December~~our ~~31,~~Northeast ~~2017~~Wattenberg field.

(2)The ~~data~~increase in ~~the~~proved ~~above~~undeveloped ~~table represent estimates only. Oil, natural gas and NGLs~~ reserves ~~are~~for ~~estimates~~the ofyear ~~accumulations~~ended ~~of oil~~December 31, ~~natural~~2018 ~~gas~~was ~~and~~primarily ~~NGLs~~related ~~that~~to ~~cannot~~the beaddition ~~measured exactly. The accuracy~~ of ~~any~~the ~~reserves~~Hereford ~~estimate~~field isas a ~~function~~result of the ~~quality~~2018 ofMerger ~~available~~with ~~data~~Fifth ~~and~~Creek. ~~engineering~~The ~~and~~upward ~~geological~~revisions ~~interpretation~~include ~~and judgment~~41.0 ~~Accordingly,~~MMboe ~~reserves~~related ~~estimates~~to ~~may~~the ~~vary~~Hereford ~~from~~field ~~the~~that ~~quantities~~were ofadded ~~oil,~~to ~~natural~~the ~~gas~~proved ~~and~~undeveloped ~~NGLs~~reserve ~~that~~category ~~are~~as ~~ultimately~~these ~~recovered.~~locations ~~See~~are ~~"Item~~included ~~1A.~~in ~~Risk~~our ~~Factors"~~near-term development plans.

~~The~~(3)Negative ~~following~~engineering ~~tables~~revisions ~~illustrate~~for the ~~history~~year ended December 31, 2018 of ~~our~~6.7 ~~proved~~MMBOE ~~undeveloped~~are ~~reserves~~composed of 2.9 MMBoe at Hereford due to results from ~~December 31~~nine drilled but not completed (“DUC”) wells acquired in the 2018 Merger which were testing tighter well spacing, ~~2017~~and ~~through~~two ~~December 31~~of which experienced mechanical issues, ~~2019:~~and 3.8 MMBoe at Northeast Wattenberg due to well under performance in a new development.

	As of December 31,
Proved Undeveloped Reserves:	2019		2018		2017
	(MMBoe)
Beginning balance	53.2		44.3		18.5
Additions from drilling program (1)(2)	32.2		41.3		31.7
Acquisitions	1.9		5.2		—
Engineering revisions (3)	0.8		(6.7	)	10.8
Price revisions	(0.4	)	0.2		0.2
Converted to proved developed	(12.1	)	(21.1	)	(13.0	)
Sold/ expired/ other (4)	—		(10.0	)	(3.9	)
Total proved undeveloped reserves (5)	75.6		53.2		44.3

(4)For the year ended December 31, 2020 proved undeveloped reserves of 65.9 MMboe were removed based on the information described above.

(15)For ~~The~~the ~~increase~~year inended December 31, 2018, 10.0 MMboe of proved undeveloped reserves ~~for~~in ~~the~~our ~~year~~Northeast ~~ended~~Wattenberg ~~December~~field ~~31,~~were ~~2019~~removed ~~was~~due ~~related~~ to the ~~expansion~~2018 ofMerger ~~our~~as ~~drilling~~a ~~program~~result inof ~~the~~focusing ~~Hereford~~our ~~field~~drilling ~~and~~plans ato ~~successful~~target ~~extension~~the ~~test~~higher inreturn ~~our~~locations ~~Northeast~~in ~~Wattenberg~~the Hereford field.

(2) The increase in proved undeveloped reserves for the year ended December 31, 2018 was primarily related to the addition of the Hereford field as a result of the Merger with Fifth Creek. The upward revisions include 41.0 MMboe related to the Hereford field that were added to the proved undeveloped reserve category as these locations are included in our near-term development plans.


	Year Ended December 31,
	2020			2019			2018
Proved undeveloped locations converted to proved developed wells during year	31			64			69
Proved undeveloped drilling and completion capital invested (in millions)	$	77.2		$	262.4		$	269.1
Proved undeveloped facilities capital invested (in millions)	$	2.8		$	13.5		$	28.5
Percentage of proved undeveloped reserves converted to proved developed	7		%	23		%	48		%
Prior year’s proved undeveloped reserves remaining undeveloped at current year end (MMBoe)	—			42.4			11.2

~~(3)~~At ~~Negative~~December 31, ~~engineering~~2020, ~~revisions~~our ~~for~~proved ~~the~~undeveloped ~~year~~reserves ~~ended~~were ~~December~~zero. At December 31, ~~2018~~2019, ofour ~~6.7~~proved ~~MMBOE~~undeveloped ~~are~~reserves ~~composed~~were ~~of 2~~75.96 MMBoe. atDuring ~~Hereford~~2020, ~~due~~5.5 toMMBoe, ~~results~~or ~~from~~7% ~~nine~~of ~~drilled~~our ~~but~~December 31, ~~not~~2019 ~~completed~~proved undeveloped reserves (~~"DUC")~~31 wells), ~~acquired~~were inconverted ~~the~~into ~~Merger~~proved ~~which~~developed ~~were~~reserves ~~testing~~and required $77.2 million of drilling and completion capital and $2.8

810

Table of Contents

~~tighter~~million ~~well~~of ~~spacing,~~facilities ~~and~~capital. ~~two~~These ofwells ~~which~~produced ~~experienced~~2.8 ~~mechanical~~MMBoe ~~issues~~in 2020. During 2020, ~~and~~we ~~3.8~~reduced ~~MMBoe~~our atproved ~~Northeast~~undeveloped ~~Wattenberg~~reserves by 65.9 MMboe due to ~~well~~suspending ~~under~~our ~~performance~~drilling and completion programs for the foreseeable future in aour ~~new~~core development areas. Negative engineering revisions decreased proved undeveloped reserves by 4.0 MMBoe. Negative pricing revisions decreased proved undeveloped reserves by 0.2 MMBoe.

(4) For the year ended December 31, 2018, 10.0 MMboe of proved undeveloped reserves in our Northeast Wattenberg field were removed due to the Merger as a result of focusing our drilling plans to target the higher return locations in the Hereford field.

(5) Our proved undeveloped locations as of December 31, 2019 represent approximately 7 rig-years of drilling inventory which we currently plan to develop over the next 2 to 3 years. This proved undeveloped inventory represents a conservative investment decision to drill these locations within the five-year development window allowed at the time the applicable proved undeveloped reserve is booked and is only a small portion of our large resource base, much of which meets the engineering definition for proved undeveloped reserves. However, the timing of such drilling is subject to change based on a number of factors, many of which are unpredictable and beyond our control, such as changes in commodity prices, anticipated cash flows and projected rate of return, access to capital, new opportunities with better returns on investment that were not known at the time of the reserve report, asset acquisitions and/or sales and actions or inactions of other co-owners or industry operators. As such, the relative proportion of total proved undeveloped locations that we develop may not necessarily be uniform from year to year, but could vary by year based upon the foregoing factors. We attempt to maximize the rate of return on capital deployed, which requires that we continually review all investment options available. As a result, at times we may delay or remove the drilling of certain projects, including scheduled proved undeveloped locations, in favor of projects with more attractive rates of return, leading us to deviate from our original development plan.

	Year Ended December 31,
	2019			2018			2017
Proved undeveloped locations converted to proved developed wells during year	64			69			51
Proved undeveloped drilling and completion capital invested (in millions)	$	262.4		$	269.1		$	136.8
Proved undeveloped facilities capital invested (in millions)	$	13.5		$	28.5		$	11.9
Percentage of proved undeveloped reserves converted to proved developed	23		%	48		%	70		%
Prior year's proved undeveloped reserves remaining undeveloped at current year end (MMBoe)	42.4			11.2			1.6

At December 31, 2019, our proved undeveloped reserves were 75.6 MMBoe. At December 31, 2018, our proved undeveloped reserves were 53.2 MMBoe. During 2019, 12.1 MMBoe, or 23% of our December 31, 2018 proved undeveloped reserves (64 wells), were converted into proved developed reserves and required $262.4 million of drilling and completion capital and $13.5 million of facilities capital. These wells produced 2.8 MMBoe in 2019. During 2019, we added 32.2 MMBoe of proved undeveloped reserves due to drilling programs in our core development area. Positive engineering revisions increased proved undeveloped reserves by 0.8 MMBoe. Negative pricing revisions decreased proved undeveloped reserves by 0.4 MMBoe. The proved undeveloped reserves from December 31, 2018 that remained in the proved undeveloped reserves category at December 31, 2019 were 42.4 MMBoe.

At December 31, 2018, our proved undeveloped reserves were 53.2 MMBoe. At December 31, 2017, our proved undeveloped reserves were 44.3 MMBoe. During 2018, 21.1 MMBoe, or 48% of our December 31, 2017 proved undeveloped reserves (69 wells), were converted into proved developed reserves and required $269.1 million of drilling and completion capital and $28.5 million of facilities capital. These wells produced 2.9 MMBoe in 2018. During 2018, we added 41.3 MMBoe of proved undeveloped reserves due to drilling programs in our core development area. Negative engineering revisions decreased proved undeveloped reserves by 6.7 MMBoe as discussed above. During 2018, 10.0 MMBoe were removed from the proved undeveloped reserves category as a result of being excluded from our near term development plans within the five year development window allowed at the time the applicable proved undeveloped reserves were booked. Positive pricing revisions increased proved undeveloped reserves by 0.2 MMBoe. The proved undeveloped reserves from December 31, 2017 that remained in the proved undeveloped reserves category at December 31, 2018 were 11.2 MMBoe.

At December 31, 2017, our proved undeveloped reserves were 44.3 MMBoe. At December 31, 2016, our proved undeveloped reserves were 18.5 MMBoe. During 2017, 13.0 MMBoe, or 70% of our December 31, 2016 proved undeveloped reserves (51 wells), were converted into proved developed reserves and required $136.8 million of drilling and completion capital and $11.9 million of facilities capital. These wells produced 2.2 MMBoe in 2017. During 2017, we added 31.7 MMBoe of proved undeveloped reserves due to drilling programs in our core development area. Positive engineering revisions increased

Table of Contents

proved undeveloped reserves by 10.8 MMBoe. During 2017, 3.9 MMBoe were removed from the proved undeveloped reserves category because they were not included in our near term development plans within the five year development window allowed at the time the applicable proved undeveloped reserves were booked. Positive pricing revisions increased proved undeveloped reserves by 0.2 MMBoe. The proved undeveloped reserves from December 31, 2016 that remained in the proved undeveloped reserves category at December 31, 2017 were 1.6 MMBoe.

We use our internal reserves estimates rather than the estimates of an independent third party engineering firm because we believe that our reservoir and operations engineers are more knowledgeable about the wells due to our continual analysis throughout the year as compared to the relatively short term analysis performed by third party engineers. We use our internal reserves estimates on all properties regardless of the positive or negative variance relative to the estimates of third party engineers. If a variance greater than 10% occurs at the field level, it may suggest that a difference in methodology or evaluation techniques exists between us and the third party engineers. We investigate any such differences and discuss the differences with the third party engineers to confirm that we used the proper methodologies and techniques in estimating reserves for the relevant field. These variances also are reviewed with our Reserves and EHS Committee. These differences are not resolved to a specified tolerance at the field or property level. In the aggregate, the third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates.

The internal review process of our wells and the related reserves estimates, and the related internal controls we utilize, include but are not limited to the following:

• A comparison is made and documented of actual and historical data from our production system to the data in the reserve database. This is intended to ensure the accuracy of the production data, which supplies the basis for forecasting.

• A comparison is made and documented of land and lease records to interest data in the reserve database. This is intended to ensure that the costs and revenues will be properly determined in the reserves estimation.

• A comparison is made of the historical costs (capital and expenses) to the capital and lease operating costs in the reserve database. Documentation lists reasons for deviation from direct use of historical data. This is intended to ensure that all costs are properly included in the reserve database.

• A comparison is made of input data to data in the reserve database of all property acquisitions, disposals, retirements or transfers to verify that all are accounted for accurately.

• Natural gas and oil prices based on the SEC pricing requirements are supplied by the third party independent engineering firm. Natural gas pricing for the first flow day of every month is collected from Henry Hub Gas Daily price and oil pricing is collected from Thomson Reuters WTI spot price. The average NGL price is based on a percentage of the WTI oil price per barrel.

• A final check is made of all economic data inputs in the reserve database by comparing them to documentation provided by our internal marketing, land, accounting, production and operations groups. This provides a second check designed to ensure accuracy of input data in the reserve database.

• Accurate classification of reserves is verified by comparing independent classification analyses by our internal reservoir engineers and the third party engineers. Discrepancies are discussed and differences are jointly resolved.

• Internal reserves estimates are reviewed by well and by area by the Chief Operating Officer. A variance by well to the previous year-end reserve report is used in this process. This review is independent of the reserves estimation process.11

• Reserves variances are discussed among the internal reservoir engineers and the Chief Operating Officer. Our internal reserves estimates are reviewed by senior management and the Reserves and EHS Committee prior to publication.

Within our Company, the technical person primarily responsible for overseeing the preparation of the reserves estimates is Paul Geiger. Mr. Geiger is our Chief Operating Officer and became responsible for our reserves estimates starting in January 2019. Mr. Geiger earned a Bachelor of Science degree in Petroleum Engineering and an MBA from the University of Texas. Mr. Geiger has over 20 years of experience in reserves and economic evaluations, as well as broad experience in production, completions, reservoir analysis and planning and development.

Table of Contents

~~Miami,~~•Internal ~~Florida,~~reserves inestimates ~~1976~~are ~~with~~reviewed aby ~~Bachelor~~well ~~of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography;~~ and ~~from~~by ~~Saint~~area ~~Mary's~~by ~~College~~the ofChief ~~California~~Operating ~~in 1989 with a Master of Business Administration Degree~~Officer. ~~Both~~A ~~technical~~variance ~~principals~~by ~~meet~~well orto ~~exceed~~ the ~~education,~~previous ~~training,~~year-end ~~and~~reserve ~~experience~~report ~~requirements~~is ~~set~~used ~~forth~~ in ~~the~~this ~~Standards~~process. ~~Pertaining~~This toreview ~~the~~is ~~Estimating~~independent ~~and Auditing~~ of ~~Oil and Gas Reserves Information promulgated by~~ the ~~Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry~~ reserves ~~definitions~~estimation ~~and guidelines~~process.

~~NSAI~~•Reserves ~~performed~~variances aare ~~well-by-well~~discussed ~~audit~~among ofthe ~~all~~internal ofreservoir ~~our~~engineers ~~properties~~ and ofthe ~~our~~Chief ~~estimates~~Operating ofOfficer. ~~proved~~Our internal reserves ~~and then provided us with its audit report concerning our~~ estimates. ~~The~~are ~~audit~~reviewed ~~completed~~ by ~~NSAI,~~senior atmanagement ~~our~~and ~~request, is a collective application of a series of procedures performed by NSAI. These audit procedures may be~~ the ~~same~~Reserves ~~as or different from audit procedures performed by other independent third party engineering firms for other oil~~ and ~~gas~~EHS ~~companies.~~Committee ~~NSAI's~~prior ~~audit report does not state the degree of its concurrence with the accuracy of our estimate of the proved reserves attributable~~ to ~~our interest in any specific basin, property or well~~publication.

The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein are Mr. Benjamin W. Johnson and Mr. John G. Hattner. Mr. Johnson, a Licensed Professional Engineer in the State of Texas (No. 124738), has been practicing consulting petroleum engineering at NSAI since 2007 and has over 2 years of prior industry experience. He graduated from Texas Tech University in 2005 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Hattner, a Licensed Professional Geoscientist in the State of Texas, Geophysics (No. 559), has been practicing consulting petroleum geoscience at NSAI since 1991, and has over 11 years of prior industry experience. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary’s College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed 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; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

NSAI performed a well-by-well audit of all of our properties and of our estimates of proved reserves and then provided us with its audit report concerning our estimates. The audit completed by NSAI, at our request, is a collective application of a series of procedures performed by NSAI. These audit procedures may be the same as or different from audit procedures performed by other independent third party engineering firms for other oil and gas companies. NSAI’s audit report does not state the degree of its concurrence with the accuracy of our estimate of the proved reserves attributable to our interest in any specific basin, property or well.

The NSAI audit process is intended to determine the percentage difference, in the aggregate, of our internal net proved reserves estimate and future net revenue (discounted at 10%) and the reserves estimate and net revenue as determined by NSAI. The audit process includes the following:

• The NSAI engineer performs an independent decline curve analysis on proved producing wells based on production and pressure data.

• The NSAI engineer may verify the production data with public data.

• The NSAI engineer uses his or her individual interpretation of the information and knowledge of the reservoir and area to make an independent analysis of proved producing reserves.

• The NSAI technical staff may prepare independent maps and volumetric analyses on our properties and offsetting properties. They review our geologic maps, log data, core data, pertinent pressure data, test information and pertinent technical analyses, as well as data from offsetting producers.

• For the reserves estimates of proved non-producing and proved undeveloped locations, the NSAI engineer will estimate the potential for depletion by analogy to other wells in the basin drilled on varying well spacing.

• The NSAI engineer will estimate the hydrocarbon recovery of the remaining gas-in-place based upon his/her knowledge and experience.

• The NSAI engineer does not verify our working and net revenue interests or product price deductions.

• The NSAI engineer does not verify our capital costs although he/she may ask for confirming information and compare to basin analogs.

• The NSAI engineer reviews 12 months of operating cost, revenue and pricing information that we provide.

• The NSAI engineer confirms the oil and gas prices used for the SEC reserves estimate.

• NSAI confirms that its reserves estimate is within a 10% variance of our internal net reserves estimate and estimated future net revenue (discounted at 10%), in the aggregate, before an audit letter is issued.

• The audit by NSAI is not performed such that differences in reserves or revenue on a well level are resolved to any specific tolerance.

The reserves audit letter provided by NSAI states that "in our opinion the estimates shown herein of HighPoint's reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards." The audit letter also includes a statement of dates pertaining to the NSAI work performed, the methodology used, the assumptions made and a discussion of uncertainties that they believe are inherent in reserves estimates.12

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure shown in the Financial Statements should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board pronouncements ("FASB"), is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

From time to time, we engage NSAI to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. NSAI and its employees have no interest in those properties, and the compensation for these engagements is not contingent on NSAI's estimates of reserves and future cash inflows for the subject properties. During 2019 and 2018, we paid NSAI approximately $245,000 and $233,000, respectively, for auditing our reserves estimates.

Table of Contents

The reserves audit letter provided by NSAI states that “in our opinion the estimates shown herein of HighPoint’s reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards.” The audit letter also includes a statement of dates pertaining to the NSAI work performed, the methodology used, the assumptions made and a discussion of uncertainties that they believe are inherent in reserves estimates.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure shown in the Financial Statements should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board pronouncements (“FASB”), is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

From time to time, we engage NSAI to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. NSAI and its employees have no interest in those properties, and the compensation for these engagements is not contingent on NSAI’s estimates of reserves and future cash inflows for the subject properties. During 2020 and 2019, we paid NSAI approximately $110,000 and $245,000, respectively, for auditing our reserves estimates.

Table of Contents

Production and Cost History

The following table sets forth information regarding net production of oil, natural gas and NGLs and certain cost information for each of the periods indicated:

	~~Year Ended December 31,~~		Year Ended December 31,
	2019				2018		2017
			2020				2019		2018
Company Production Data:
Oil (MBbls)	~~7,668~~		5,909		~~6,330~~		47,~~203~~668		6,330
Natural gas (MMcf)	~~16,614~~		16,428		~~12,864~~		816,~~952~~614		12,864
NGLs (MBbls)	~~2,101~~		2,352		~~1,697~~		12,~~307~~101		1,697
Combined volumes (MBoe)	~~12,538~~		10,999		~~10,171~~		712,~~002~~538		10,171
Daily combined volumes (Boe/d)	~~34,351~~		30,052		~~27,866~~		1934,~~184~~351		27,866
DJ Basin – Production Data (1):
Oil (MBbls)	~~7,668~~		5,879		~~6,330~~		37,~~509~~668		6,330
Natural gas (MMcf)	~~16,614~~		16,374		~~12,864~~		816,~~592~~614		12,864
NGLs (MBbls)	~~2,101~~		2,345		~~1,697~~		12,~~294~~101		1,697
Combined volumes (MBoe)	~~12,538~~		10,953		~~10,171~~		612,~~235~~538		10,171
Daily combined volumes (Boe/d)	~~34,351~~		29,926		~~27,866~~		1734,~~082~~351		27,866
Uinta Oil Program – Production Data (1)(2):
Average Realized Prices before Hedging:
Oil (MBbls)	—				—		689
Oil (per Bbl)			$	34.62			$	52.86	$	62.04
Natural gas (MMcf)	—				—		348
Natural gas (per Mcf)			1.33				1.56		1.75
NGLs (MBbls)	—				—		12
NGLs (per Bbl)			9.69				10.00		22.18
Combined volumes (MBoe)	—				—		759
Combined (per Boe)			22.66				36.07		44.53
Daily combined volumes (Boe/d)	—				—		2,079
Average Realized Prices with Hedging:
Average Realized Prices before Hedging:
Oil (per Bbl)			$	53.25			$	54.39	$	54.51
Oil (per Bbl)	$	52.86			$	62.04	$	48.37
Natural gas (per Mcf)			1.30				1.50		1.76
Natural gas (per Mcf)	1.56				1.75		2.43
NGLs (per Bbl)			9.69				10.00		22.18
NGLs (per Bbl)	10.00				22.18		20.01
Combined (per Boe)			32.62				36.92		39.85
Combined (per Boe)	36.07				44.53		35.88
Average Costs ($ per Boe):
Average Realized Prices with Hedging:
Lease operating expense			$	2.96			$	3.01	$	2.74
Oil (per Bbl)	$	54.39			$	54.51	$	52.72
Gathering, transportation and processing expense			1.68				0.85		0.46
Natural gas (per Mcf)	1.50				1.76		2.52
Total production costs excluding production taxes			$	4.64			$	3.86	$	3.20
NGLs (per Bbl)	10.00				22.18		20.01
Production tax expense (2)			(0.06)				1.88		3.61
Combined (per Boe)	36.92				39.85		38.60
Depreciation, depletion and amortization			13.55				25.62		22.46
Average Costs ($ per Boe):
General and administrative (3)			3.92				3.57		4.44
Lease operating expense	$	3.01			$	2.74	$	3.46
Gathering, transportation and processing expense	0.85				0.46		0.37
Total production costs excluding production taxes	$	3.86			$	3.20	$	3.83
Production tax expense	1.88				3.61		2.07
Depreciation, depletion and amortization	25.62				22.46		22.85
General and administrative (3)	3.57				4.44		6.07

(1) The DJ Basin was the only development area that contained 15% or more of our total proved reserves as of December 31, ~~2019~~2020, ~~2018~~2019 and ~~2017~~2018.

(2)Production Ontaxes for the year ended December 2931, ~~2017,~~2020 weincluded ~~completed~~reductions ~~the~~of ~~sale~~$7.3 ofmillion ~~our~~and ~~remaining~~$5.4 ~~non-core~~million, ~~assets~~respectively, inassociated ~~the~~with ~~Uinta~~a ~~Basin.~~true-up Asto aactual ~~result,~~2018 ~~the~~Colorado ~~production~~ad valorem taxes and ~~cost~~an ~~data~~adjustment ~~related~~to estimated 2019 Colorado ad valorem taxes to ~~the~~be ~~Uinta~~paid ~~Basin~~in 2021 as ~~reported~~a ~~above~~result ~~includes~~of ~~values~~refunds ~~through~~and ~~the~~new ~~closing~~information ~~date~~received ofin ~~December~~2020. 29In addition, ~~2017~~production taxes were reduced by $1.5 ~~See~~million ~~Note~~associated 4with a true up to ~~the~~2019 ~~Consolidated~~Colorado ~~Financial~~severance ~~Statements~~taxes as a result of refunds received and by $1.8 million to account for ~~more~~Colorado ~~information~~severance ~~related~~tax refunds based on an audit of tax years 2015 to ~~this~~2017. ~~divestiture~~Excluding these adjustments, production taxes would have been $1.48 per Boe.

12(3)Included in general and administrative expense is long-term cash and equity incentive compensation of $3.5 million (or $0.32 per Boe), $8.6 million (or $0.69 per Boe) and $7.2 million (or $0.71 per Boe) for the years ended December 31, 2020, 2019 and 2018, respectively.

Table of Contents

(3) Included in general and administrative expense is long-term cash and equity incentive compensation of $8.6 million (or $0.69 per Boe), $7.2 million (or $0.71 per Boe) and $8.3 million (or $1.18 per Boe) for the years ended December 31, 2019, 2018 and 2017, respectively.

Productive Wells

The following table sets forth information at December 31, ~~2019~~2020 relating to the productive wells in which we owned a working interest as of that date.

~~Oil~~

Oil

~~Gas~~

Gas

Basin/Area

~~Gross Wells~~

~~Net Wells~~

Gross Wells

~~Gross Wells~~

~~Net Wells~~

Net Wells

Gross Wells

Net Wells

~~558.0~~

~~371.4~~

558.0

~~10.0~~

~~6.5~~

389.4

8.0

7.1

Other

~~1.0~~

~~0.1~~

4.0

~~4.0~~

~~1.1~~

0.3

4.0

1.2

Total

~~559.0~~

~~371.5~~

562.0

~~14.0~~

~~7.6~~

389.7

12.0

8.3

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, ~~2019~~2020 relating to our leasehold acreage.

~~Developed Acreage~~

Developed Acreage

~~Undeveloped Acreage~~

Undeveloped Acreage

Basin/Area

~~Gross~~

~~Net~~

Gross

~~Gross~~

~~Net~~

Net

Gross

Net

~~95,790~~

~~76,544~~

93,441

~~97,860~~

~~66,043~~

76,961

80,133

54,722

Other (1)

~~4,923~~

~~2,093~~

4,922

~~114,564~~

~~54,819~~

2,093

112,492

51,412

Total

~~100,713~~

~~78,637~~

98,363

~~212,424~~

~~120,862~~

79,054

192,625

106,134

(1) Other includes 4645,~~583,~~188 ~~4,184 and 2,353~~ net undeveloped acres in the Paradox, ~~Piceance and Deseret Basins, respectively~~Basin.

Substantially all of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth, as of December 31, ~~2019~~2020, the expiration periods of the net undeveloped acres by area that are subject to leases summarized in the above table of undeveloped acreage.

	~~Net Undeveloped Acres Expiring~~		Net Undeveloped Acres Expiring
Basin/Area	~~2020~~	~~2021~~	2021	~~2022~~	~~2023~~	2022	~~Thereafter~~	~~Total~~	2023	2024	Thereafter (1)	Total
DJ	~~7,932~~	~~15,020~~	14,537	~~7,348~~	~~5,611~~	7,091	~~30,132~~	~~66,043~~	5,489	19	27,586	54,722
Other	~~2,012~~	—	—	—	~~288~~	—	~~52,519~~	~~54,819~~	288	—	51,124	51,412
Total	~~9,944~~	~~15,020~~	14,537	~~7,348~~	~~5,899~~	7,091	~~82,651~~	~~120,862~~	5,777	19	78,710	106,134

13(1)Thereafter includes 11,178 acres in the DJ and 45,922 acres in other that are held by production.

Table of Contents

Drilling Results

The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities or value of reserves found.

	Year Ended December 31,
	2019		2018		2017
	Gross	Net	Gross	Net	Gross	Net
Development
Productive	106.0	67.2	95.0	76.1	59.0	44.8
Dry	—	—	—	—	—	—
Exploratory
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total
Productive	106.0	67.2	95.0	76.1	59.0	44.8
Dry	—	—	—	—	—	—

Table of Contents


	Year Ended December 31,
	2020		2019		2018
	Gross	Net	Gross	Net	Gross	Net
Development
Productive	34.0	25.0	106.0	67.2	95.0	76.1
Dry	—	—	—	—	—	—
Exploratory
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total
Productive	34.0	25.0	106.0	67.2	95.0	76.1
Dry	—	—	—	—	—	—

Operations

General

In general, we serve as operator of wells in which we have a greater than 50% working interest. In addition, we seek to be the operator of wells in which we have lesser interests. As operator, we obtain regulatory authorizations, design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or the majority of the other oil field service equipment used for drilling or maintaining wells on the properties we operate. Independent contractors engaged by us provide the majority of the equipment and personnel associated with these activities. In certain circumstances we construct, operate and maintain gas gathering and water facilities associated with our operations. We employ drilling, completion, facility, production and reservoir engineers and geologists and other specialists who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties. We strive to minimize our impact on the communities in which we operate.

Marketing and Customers

We market all of the oil production from our operated properties. Our oil production is sold to a variety of purchasers under contracts with daily, monthly, seasonal, annual or multi-year terms, all at market prices. Purchasers include pipelines, processors, refineries, marketing companies and end users. Our oil contracts are priced off of New York Mercantile Exchange ("“NYMEX"”) with quality, location or transportation differentials.

Our natural gas and related NGLs are generally marketed by third parties under percentage of proceeds ("“POP"”) or fee-based contracts. Based on where we operate and the availability of other purchasers and markets, we believe that our production could be sold in the market in the event that it is not sold to our existing customers. However, in some circumstances, a change in customers may entail significant transition costs.

We normally sell production to a relatively small number of customers, as is customary in the development and production business. During ~~2019~~2020, ~~three~~four customers individually accounted for over 10% of our oil, gas and NGL production revenues. During ~~2018~~2019, ~~four~~three customers individually accounted for over 10% of our oil, gas and NGL production revenues. During ~~2017~~2018, ~~three~~four customers individually accounted for over 10% of our oil, gas and NGL production revenues.

The following table sets forth information about a material long-term firm oil pipeline transportation contract, which entails a demand charge for reservation of capacity. This contract was initiated to mitigate rising transportation costs in our Hereford field in the DJ Basin. This firm transportation contract requires the pipeline to provide transportation capacity and requires us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized and will expire April 30, 2025. The costs of this transportation contract are included in oil, gas and NGL production in the Consolidated Statements of Operations.

Table of Contents

2025. The costs of this transportation contract are included in oil, gas and NGL production in the Consolidated Statements of Operations.

Type of Arrangement

Pipeline System / Location

Deliverable Market

Range of Gross Deliveries (Bbl/d)

Term

Firm Transport

Tallgrass Pony Express

Cushing

6,250-12,500

05/20 – 04/25

The following table sets forth information about material long-term firm natural gas pipeline transportation contracts, which entail a demand charge for reservation of capacity. These contracts were initiated to provide a guaranteed outlet for company-marketed production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized and expire July 31, 2021. These transportation costs are included in unused commitments expense in the Consolidated Statements of Operations. 16

Table of Contents

The following table sets forth information about material long-term firm natural gas pipeline transportation contracts, which entail a demand charge for reservation of capacity. These contracts were initiated to provide a guaranteed outlet for company-marketed production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized and will expire July 31, 2021. These transportation costs are included in unused commitments expense in the Consolidated Statements of Operations.

Type of Arrangement

Pipeline System / Location

Deliverable Market

Gross Deliveries (MMBtu/d)

Term

Firm Transport

Questar Overthrust

Rocky Mountains

50,000

08/11 – 07/21

Firm Transport

Ruby Pipeline

West Coast

50,000

08/11 – 07/21

Hedging Activities

Our hedging program is intended to mitigate the risks of volatile prices of oil, natural gas, and NGLs. ~~Our strategic objective is to hedge 50% to 70% of our anticipated production on a forward 12-month to 18-month basis.~~ As of February 4, ~~2020~~2021, we have hedged 53,~~857~~098,~~500~~000 barrels ofand ~~oil~~365,000 ~~for~~barrels of our ~~2020~~expected 2021 and 2022 oil production, respectively, and 17,~~912~~590,~~500~~000 ~~barrels~~MMbtu ofand ~~oil~~3,650,000 ~~for~~MMbtu of our expected 2021 and 2022 natural gas production, respectively, at price levels that provide some economic certainty to our cash flows. Currently, ~~nine~~7 of our 11 lenders (or affiliates of lenders) under our ~~credit~~Credit ~~facility~~Facility are also hedging counterparties. We are not required to post collateral for these hedges other than the security for our ~~credit~~Credit ~~facility~~Facility. For additional information on our hedging activities, see "“Item 7A. Quantitative and Qualitative Disclosures About Market Risk"”.

Competition

The oil and gas industry is intensely competitive, and we compete with a large number of other companies, some of which have greater resources. See the risk discussed below in "“Item 1A. Risk Factors"” under the caption "“Competition in the oil and gas industry is intense, which may adversely affect our ability to succeed"”.

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved developed reserves. Prior to the commencement of drilling operations on those properties, we typically conduct a title examination and perform curative work for significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing such defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we utilize methods consistent with practices customary in the oil and gas industry and that our practices are adequately designed to enable us to acquire satisfactory title to our producing properties. Prior to completing an acquisition of producing oil and gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. However, our title review processes may not be successful in preventing disputes and losses related to actual or asserted title defects. Our oil, natural gas and NGL producing properties are subject to customary royalty and other interests, liens for current taxes, liens under our ~~Amended~~ Credit Facility and other burdens that we believe do not materially interfere with the use of our properties.

Environmental Matters and Regulation

General. Our operations are subject to comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment, management of E&P waste, or otherwise relating to environmental protection and minimization of aesthetic impacts. Our operations are generally subject to the same environmental laws and regulations as other companies in the oil and gas exploration and production industry in the areas where we operate. These laws and regulations:

15•require the acquisition of various permits before drilling commences;

•require the installation and proper maintenance of effective emission control equipment;

•restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

•limit or prohibit drilling activities on lands lying within environmentally sensitive areas, wilderness, wetlands and other protected areas, including areas proximate to residential areas and certain high-occupancy buildings;

•require measures to prevent pollution from current operations, such as E&P waste management, transportation and disposal requirements;

Table of Contents

~~regulations:~~•require measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

•impose ~~require~~substantial ~~the~~penalties ~~acquisition~~for ofany ~~various~~non-compliance ~~permits~~with ~~before~~federal, ~~drilling~~state ~~commences~~and local laws and regulations;

•impose ~~require~~substantial ~~the~~liabilities ~~installation~~for ofany ~~effective~~pollution ~~emission~~resulting ~~control~~from ~~equipment~~our operations;

•with ~~restrict~~respect ~~the~~to ~~types,~~operations ~~quantities~~affecting ~~and~~federal ~~concentration~~lands ofor ~~various~~leases, ~~substances~~require ~~that~~time ~~can~~consuming beenvironmental ~~released~~analysis ~~into the environment in connection~~ with ~~drilling~~uncertain ~~and production activities~~outcomes;

•expose ~~limit~~us orto ~~prohibit~~litigation ~~drilling~~by ~~activities~~environmental ~~on lands lying within environmentally sensitive areas, wilderness, wetlands~~ and other ~~protected~~special ~~areas,~~interest ~~including~~groups; ~~areas proximate to residential areas~~ and ~~certain high-occupancy buildings;~~

•impose ~~require~~certain ~~measures~~compliance ~~to prevent pollution from current operations, such as E&P waste management, transportation~~ and ~~disposal~~regulatory reporting requirements;.

• require measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

• impose substantial penalties for any non-compliance with federal, state and local laws and regulations;

• impose substantial liabilities for any pollution resulting from our operations;

• with respect to operations affecting federal lands or leases, require time consuming environmental analysis with uncertain outcomes;

• expose us to litigation by environmental and other special interest groups; and

• impose certain compliance and regulatory reporting requirements.

These laws, rules and regulations may also restrict the rate of oil, natural gas and NGLs production below the rate that would otherwise be possible, for example, by limiting the flaring of associated natural gas from an oil well while awaiting a pipeline connection. The regulatory burden on the oil and gas industry increases the cost and delays the timing of doing business and consequently affects profitability. Additionally, Congress, state legislatures, and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs.

We have made and will continue to make expenditures in our efforts to comply with all environmental regulations and requirements. We consider these a normal, recurring cost of our ongoing operations and not extraordinary. We believe that our compliance with existing requirements has been accounted for and will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict the passage of or quantify the potential impact of more stringent future laws and regulations, including organized, well-funded "“keep it in the ground"” efforts to turn public opinion against the use of fossil fuels. For example, statewide ballot initiatives intended to impose further restrictions on oil and gas development have been pursued several times in recent years in Colorado. In particular, Proposition 112, which was included on the ballot for the November 2018 election in Colorado but was defeated at the polls, would have amended the Colorado Oil and Gas Conservation Act to, among other things, require all new oil and gas development not on federal land to be located at least 2,500 feet away from any occupied structure or broadly defined "vulnerable area". If enacted, Proposition 112 would have effectively prohibited drilling activities across a substantial majority of the surface area of the State of Colorado, although we developed a plan to reconfigure drilling units and relocate most of our remote, rural well locations. Such reconfiguration and relocation would, however, have entailed substantial expense and delay, as well as reduced certain cost efficiencies built into our current plans. Similar proposals may be approved for the 2020 and subsequent elections. Because substantially all of our operations and reserves are located in Colorado, the passage and implementation of any such proposal could have a materially adverse effect on our operations, reserves, financial condition and business generally.

~~Similarly,~~In ~~although~~2018 ~~Proposition 112 failed at the ballot box, 44% of the electorate, representing over one million voters, cast ballots in favor. At the same time,~~ a new Democratic Governor was elected, along with Democratic majorities in both chambers of the General Assembly. Following the November 2018 election, Colorado enacted Senate Bill 19-181 ("“SB 19-181"”), which, among other things, authorizes local governments to approve the siting of and regulate the surface impacts from oil and natural gas facilities, and empowers them to adopt requirements and impose conditions that are more stringent than state regulations. The statute changes the mission of the Colorado Oil and Gas Conservation Commission (the "“COGCC"”) from fostering responsible and balanced development to regulating development to protect public health and the environment as the primary goal. It requires the COGCC to undertake rulemaking on environmental protection, facility siting, cumulative impacts, flowline safety, orphan wells, financial assurance, wellbore integrity, and application fees. It also requires the Air Quality Control Commission to review its leak detection and repair regulations and adopt rules to further minimize emissions of hydrocarbons and nitrogen oxides. These rulemakings, some of which were completed in late 2019 and ~~others that will be completed in~~ 2020 ~~and beyond~~, ~~will~~have ~~impose~~imposed new approval and operating requirements and may have an adverse effect on our development program, particularly in terms of costs and delays in the permitting process and the siting of new wells. The majority of these regulations were approved late in 2020 and became effective on January 15, 2021, and the COGCC is still in the process of issuing guidance and direction on implementation of the new regulations. However, we believe that the location of our assets in rural areas of Weld County, a jurisdiction generally supportive of oil and gas development, is likely to mitigate these impacts to a significant extent. Additionally, our staff were extensively involved in the rulemaking process throughout 2020 and we believe that we have been able to effectively evaluate the new requirements and implement the measures necessary to maintain compliance with the new regulations.

Table of Contents

Other environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry and our business include the following:

National Environmental Policy Act. Oil, natural gas and NGLs exploration and production activities on federal lands and the development of federal mineral rights are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Departments of the Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an environmental assessment prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project and project alternatives. If impacts are considered significant, the agency will prepare a more detailed Environmental Impact Statement. These environmental analyses are made available for public review and comment. On January 10, 2020, the Council on Environmental Quality ("“CEQ"”) published a notice of proposed rulemaking that seeks comment on potential amendments that would "“modernize and clarify"” the current NEPA regulations and streamline environmental reviews. Potential amendments to the NEPA regulations could include setting time limits for completion of environmental reviews and no longer requiring federal agencies to consider the cumulative impacts of a project. The public comment period on the notice for proposed rulemaking ~~ends~~ended on March 10, 2020. The ~~proposed~~final revisions to the NEPA regulations ~~have~~were ~~not~~published ~~yet~~on ~~been~~July ~~finalized~~16, ~~and~~2020 ~~will~~with ~~likely~~an beeffective ~~subject~~date ~~to legal challenges. All~~ of ~~our~~September ~~current exploration and production activities~~14, as2020. ~~well~~Several asenvironmental ~~proposed~~groups ~~exploration~~ and ~~development~~states ~~plans,~~filed onsuit ~~federal lands~~ and~~/or~~ ~~involving~~requested ~~federal~~a ~~mineral~~preliminary ~~rights~~injunction ~~require~~to ~~governmental~~stay ~~permits that trigger~~ the ~~requirements~~implementation of ~~NEPA.~~the ~~Certain~~new ~~federal permits on non-federal lands may also trigger NEPA requirements~~rule. ~~This~~That ~~process~~motion ~~has~~was ~~the~~denied ~~potential~~and ~~to delay~~ the ~~development~~new ofrule ~~oil~~went ~~and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.~~

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes affect oil and gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of "hazardous wastes" and on the disposal of non-hazardous wastes. Under the oversight of the Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can impose administrative penalties, civil and criminal judicial actions, as well as other enforcement mechanisms for non-compliance with RCRA or corresponding state programs. RCRA also imposes cleanup liability related to the mismanagement of regulated wastes. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil, natural gas, or geothermal energy are currently exempt from regulation under the hazardous waste provisions of RCRA, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation, and legislation has been proposed from time to time in Congress to reverse the exemption. In addition, certain environmental groups petitioned and sued the EPA to reverse the exemption. The EPA entered into a consent decree with these environmental groups that committed the EPA to decide whether to revise its RCRA Subtitle D criteria regulations and state plan guidelines for the oil and natural gas sector. In April 2019 the EPA concluded that revisions to the federal regulations for the management of exploration, development and production wastes of crude oil, natural gas under Subtitle D of RCRA were not necessary. The EPA indicated that it will continue to work with states and other organizations to identify areas for continued improvement and to address emerging issues to ensure that exploration, development and production wastes continue to be managed in a manner that is protective of human health and the environment. Environmental groups, however, expressed dissatisfaction with the EPA's decision and will likely continue to press the issue at the federal and state levels.18

Table of Contents

into effect on September 14, 2020. Highlights of the new rule include presumptive limits on the amount of time required to complete the NEPA process and the number of pages needed for Environmental Assessments and Environmental Impact Statements. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands and/or involving federal mineral rights require governmental permits that trigger the requirements of NEPA. Certain federal permits on non-federal lands may also trigger NEPA requirements. This process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes affect oil and gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and on the disposal of non-hazardous wastes. Under the oversight of the Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can impose administrative penalties, civil and criminal judicial actions, as well as other enforcement mechanisms for non-compliance with RCRA or corresponding state programs. RCRA also imposes cleanup liability related to the mismanagement of regulated wastes. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil, natural gas, or geothermal energy are currently exempt from regulation under the hazardous waste provisions of RCRA, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation, and legislation has been proposed from time to time in Congress to reverse the exemption. In addition, certain environmental groups petitioned and sued the EPA to reverse the exemption. The EPA entered into a consent decree with these environmental groups that committed the EPA to decide whether to revise its RCRA Subtitle D criteria regulations and state plan guidelines for the oil and natural gas sector. In April 2019 the EPA concluded that revisions to the federal regulations for the management of exploration, development and production wastes of crude oil, natural gas under Subtitle D of RCRA were not necessary. The EPA indicated that it will continue to work with states and other organizations to identify areas for continued improvement and to address emerging issues to ensure that exploration, development and production wastes continue to be managed in a manner that is protective of human health and the environment. Environmental groups, however, expressed dissatisfaction with the EPA’s decision and will likely continue to press the issue at the federal and state levels.

Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "“Superfund"” law, imposes strict, joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be potentially responsible for a release or threatened release of a "“hazardous substance"” (generally excluding petroleum) into the environment. These persons may include current and past owners or operators of a disposal site, or site where the release or threatened release of a "“hazardous substance"” occurred, and companies that disposed of, transported or arranged for the disposal of the hazardous substance at such sites. Under CERCLA, such persons may be subject to 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. In addition, it is not uncommon for neighboring landowners and other third parties to file claims under CERCLA and/or state common law for cleanup costs, personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, could be subject to CERCLA. Governmental agencies or third parties may seek to hold us responsible under CERCLA for all or part of the costs to clean up sites at which such "“hazardous substances"” have been released.

17Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced water, storm water drainage and other oil and gas wastes, into Waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws also prohibit the discharge of dredge and fill material in regulated waters, including jurisdictional wetlands, unless authorized under a permit issued by the U.S. Army Corps of Engineers (“Corps”). Federal and state regulatory agencies can impose administrative penalties, civil and criminal penalties, and take judicial action for non-compliance with discharge permits or other requirements of the federal CWA and analogous state laws and regulations. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs may also limit the total volume of water or fill material that can be discharged, hence limiting the rate of development.

Table of Contents

~~Water~~The ~~Discharges.~~EPA ~~The~~and ~~Federal~~the ~~Water~~Corps ~~Pollution~~finalized ~~Control~~a ~~Act,~~federal ~~also~~rulemaking ~~known~~to asrevise the ~~Clean~~jurisdictional ~~Water~~definition ~~Act~~of ~~("CWA")~~“Waters of the United States” in June 2015. In February 2018, ~~and~~the ~~analogous~~EPA ~~state~~issued ~~laws~~a ~~impose~~rule ~~restrictions~~that ~~and~~delays ~~strict~~the ~~controls~~applicability ~~regarding~~of the ~~discharge~~new definition of ~~pollutants,~~the ~~including~~waters ~~produced~~of ~~water~~the United States, ~~storm~~but ~~water~~this ~~drainage~~delay ~~and~~rule ~~other~~was ~~oil~~struck ~~and~~following ~~gas~~a ~~wastes~~court challenge. Other district courts, ~~into~~however, issued rulings temporarily enjoining the applicability of the 2015 definition of “Waters of the United States.” ~~The~~Taken ~~discharge~~together, ofthe ~~pollutants~~2015 ~~into~~rule ~~regulated~~was ~~waters~~in iseffect ~~prohibited~~in 23 states, ~~except~~including inColorado, ~~accordance~~and ~~with~~temporarily stayed in the ~~terms~~remaining ofstates. aOn ~~permit~~October ~~issued~~22, by2019, the EPA orand the ~~state.~~Corps ~~These~~published ~~laws~~a ~~also~~final ~~prohibit~~rule to repeal the ~~discharge~~2015 rule defining Waters of ~~dredge~~the United States and ~~fill~~re-codify ~~material~~the inregulatory ~~regulated~~text ~~waters,~~that ~~including~~existed ~~jurisdictional~~prior ~~wetlands~~to the 2015 rule. This rule became effective on December 23, ~~unless~~2019. ~~authorized~~This ~~under~~was aconsidered ~~permit~~to ~~issued~~be “Step One” by the UEPA and the Corps.S The “Step Two” rule implemented a new definition of Waters of the United States. ~~Army~~On January 23, 2020, the EPA and the Corps ofannounced ~~Engineers~~the final new rule, titled the Navigable Waters Protection Rule (~~"Corps"~~“2020 Rule”). ~~Federal~~The ~~and~~2020 ~~state~~Rule ~~regulatory~~generally ~~agencies~~regulates ~~can~~four ~~impose~~categories ~~administrative~~of ~~penalties,~~“jurisdictional” ~~civil~~waters: (1) territorial seas and ~~criminal~~traditional ~~penalties~~navigable waters; (2) perennial and intermittent tributaries of these waters; (3) certain lakes, ponds, and ~~take~~impoundments; ~~judicial~~and ~~action~~(4) ~~for~~wetlands to jurisdictional waters. The 2020 Rule also includes 12 categories of exclusions, or “non-~~compliance~~jurisdictional” ~~with~~waters, ~~discharge~~including ~~permits~~groundwater, orephemeral ~~other~~features, ~~requirements~~and diffuse stormwater run-off over upland areas. In particular, the 2020 Rule will likely regulate fewer wetlands areas than were regulated under the prior definitions of “waters of the ~~federal~~United ~~CWA~~States” because it does not regulate wetlands that are not adjacent to jurisdictional waters. The Navigable Waters Protection Rule became effective on June 22, 2020 and ~~analogous~~is ~~state~~being ~~laws~~implemented by the EPA and ~~regulations~~the Corps in 49 of the 50 states. On June 19, 2020, the U.S. District Court for the District of Colorado stayed the effective date of the Navigable Waters Protection Rule in the State of Colorado, meaning the old definition remains in effect for all of our operations. Obtaining Clean Water Act permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs may also limit the total volume of water or fill material that can be discharged, ~~hence~~thus limiting the rate of development.

Air Emissions. The ~~EPA~~Federal Clean Air Act, and ~~the~~associated ~~Corps~~state ~~finalized~~laws aand ~~federal~~regulations, ~~rulemaking~~regulate toemissions ~~revise~~of various air pollutants through the ~~jurisdictional~~issuance ~~definition~~of permits, emission reporting, and the imposition of ~~"Waters~~emission control requirements. Most of ~~the~~our ~~United~~facilities ~~States"~~are now required to obtain permits before work can begin, and existing facilities are often required to incur additional capital costs in ~~June~~order ~~2015~~to maintain compliance with new and evolving air quality laws and regulations. In ~~February 2018~~2012, the EPA issued anew ~~rule~~New ~~that~~Source ~~delays~~Performance ~~the~~Standards ~~applicability~~(“NSPS”) ofand ~~the~~National ~~new~~Emission ~~definition~~Standards offor ~~the~~Hazardous ~~waters~~Air ofPollutants (“NESHAP”) specific to the ~~United~~oil ~~States,~~and ~~but~~gas ~~this~~industry, ~~delay~~including ~~rule~~air ~~was~~standards ~~struck~~for ~~following~~natural agas ~~court~~wells ~~challenge.~~that ~~Other~~are ~~district~~hydraulically ~~courts~~fractured, ~~however,~~and issued ~~rulings~~several ~~temporarily~~amendments ~~enjoining~~to the ~~applicability~~NSPS ofrules ~~the~~in ~~2015~~2013, ~~definition~~2014, of2015, ~~"Waters~~2016 ofand ~~the United States~~2020." ~~Taken~~In ~~together~~addition, the ~~2015~~EPA ~~rule~~has ~~was~~deemed incarbon ~~effect~~dioxide in(“CO2”) 23and ~~states~~other greenhouse gases, including ~~Colorado~~methane, ~~and~~to ~~temporarily~~be ~~stayed~~a danger to public health, which is leading to regulation of greenhouse gases in ~~the~~a ~~remaining~~manner ~~states.~~similar Onto ~~October~~other ~~22,~~pollutants. ~~2019~~For example, the EPA ~~and~~finalized amendments to the ~~Corps~~NSPS ~~published~~rules ain ~~final~~June ~~rule~~2016 tothat ~~repeal~~focused on methane emissions from the ~~2015~~oil ~~rule~~and ~~defining~~gas ~~Waters~~industry ofin ~~the~~June ~~United~~2016. ~~States~~The rules imposed, among other things, new requirements for leak detection and ~~re-codify~~repair, ~~the~~control ~~regulatory~~requirements ~~text~~for ~~that~~oil ~~existed~~well ~~prior~~completions, toreplacement ~~the~~of ~~2015~~certain ~~rule.~~pneumatic ~~This~~pumps ~~rule~~and ~~became~~controllers ~~effective~~and onadditional ~~December~~control ~~23,~~requirements ~~2019.~~for ~~This~~gathering, ~~was~~boosting ~~considered~~and tocompressor bestations. ~~"Step~~In ~~One"~~September by2018, the EPA ~~and~~proposed revisions to the ~~Corps~~2016 rules. The ~~"Step~~proposed ~~Two"~~amendments ~~rule~~address iscertain technical issues raised in administrative petitions and include proposed changes to, ~~implement~~among aother ~~new~~things, ~~definition~~the frequency of ~~Waters~~monitoring offor ~~the~~fugitive ~~United~~emissions ~~States~~at well sites and compressor stations. On ~~January~~September 2324, ~~2020,~~2019 the EPA ~~and~~proposed ~~the~~reconsideration ~~Corps~~amendments ~~announced~~to the ~~final~~NSPS ~~new~~that, ~~rule~~among other things, ~~titled~~would rescind the ~~Navigable~~methane-specific ~~Waters~~requirements ~~Protection~~of ~~Rule~~the ~~("2020~~NSPS ~~Rule")~~applicable to oil and gas production. ~~The~~ On August 13, 2020, ~~Rule~~the ~~will~~EPA goissued ~~into~~two ~~effect~~final ~~sixty~~rules ~~days~~amending ~~after~~the ~~publication~~2012 inand 2016 NSPS for the ~~Federal~~oil ~~Register~~and natural gas industry. The ~~2020~~amendments ~~Rule~~recognize ~~will~~that ~~generally~~controls ~~regulate~~used ~~four~~to ~~categories~~reduce ofVOC ~~"jurisdictional"~~emissions ~~waters:~~also ~~(1)~~reduce ~~territorial~~methane ~~seas~~emissions and, ~~traditional~~thus, ~~navigable~~rescinded ~~waters;~~the ~~(2)~~methane ~~perennial~~standards for the production and ~~intermittent~~processing ~~tributaries~~segments of ~~these~~the ~~waters;~~oil ~~(3)~~and ~~certain~~gas ~~lakes,~~industry. ~~ponds,~~Several ~~and~~other ~~impoundments;~~technical ~~and~~amendments ~~(4)~~were ~~wetlands~~made to ~~jurisdictional~~reduce ~~waters. The~~the ~~2020~~regulatory ~~Rule~~burden ~~also~~associated ~~includes~~with 12multiple ~~categories~~aspects of ~~exclusions~~the NSPS, orincluding ~~"non-jurisdictional"~~incorporating ~~waters,~~state ~~including~~fugitive ~~groundwater,~~emissions ~~ephemeral~~standards ~~features,~~for well sites and ~~diffuse~~compressor ~~stormwater~~stations ~~run-off~~in ~~over~~certain ~~upland~~states, ~~areas~~including Colorado. In ~~particular,~~Both of the ~~2020~~final ~~Rule~~rules ~~will~~are ~~likely~~currently ~~regulate~~subject ~~fewer~~to ~~wetlands~~legal ~~areas~~challenge ~~than~~in ~~were~~U.S. ~~regulated~~Court ~~under~~of Appeals for the ~~prior~~D.C. ~~definitions~~Circuit. ofOn ~~"waters~~January of20, ~~the~~2021, ~~United~~President ~~States"~~Biden ~~because~~signed itExecutive ~~does~~Order ~~not~~13990: ~~regulate~~“Protecting ~~wetlands~~Public ~~that~~Health ~~are~~and ~~not~~the ~~adjacent~~Environment and Restoring Science to ~~jurisdictional~~Tackle ~~waters~~the Climate Crisis. ~~Following~~” ~~publication~~The Executive Order established a federal policy to, ~~this~~among ~~new~~other ~~definition~~things, ofreduce ~~"waters~~greenhouse ofgas emissions. The Executive Order directs the ~~United~~EPA ~~States"~~to ~~will~~review ~~likely~~certain befederal ~~challenged~~regulations ~~and~~promulgated ~~sought~~during tothe bepreceding ~~enjoined~~4 inyears that conflict with this federal ~~court.~~policy, ~~Obtaining~~including ~~Clean~~the ~~Water~~two ~~Act~~final ~~permits~~rules ~~has~~amending the ~~potential~~2012 toand ~~delay~~2016 NSPS, discussed above. The Executive Order also directed the ~~development~~EPA to consider proposing new regulations to establish comprehensive standards of ~~oil~~performance and ~~natural~~emission ~~gas~~guidelines ~~projects.~~for ~~These~~methane ~~same~~and ~~regulatory~~volatile ~~programs~~organic ~~may~~compound ~~also~~emissions ~~limit~~from existing operations in the ~~total~~oil ~~volume~~and ofgas ~~water~~sector, orincluding ~~fill~~the ~~material~~exploration ~~that~~and ~~can~~production, betransmission, ~~discharged~~processing, ~~thus~~and ~~limiting~~storage ~~the~~segments, ~~rate~~by ofSeptember ~~development~~2021.

~~Air Emissions.~~ The Federal Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits, emission reporting, and the imposition of emission control requirements. Most of our facilities are now required to obtain permits before work can begin, and existing facilities are often required to incur additional capital costs in order to maintain compliance with new and evolving air quality laws and regulations. In 2012, the EPA issued new New Source Performance Standards ("NSPS") and National Emission Standards for Hazardous Air Pollutants ("NESHAP") specific to the oil and gas industry, including air standards for natural gas wells that are hydraulically fractured, and issued several amendments to the NSPS rules in 2013, 2014, 2015 and 2016, respectively. In addition, the EPA has deemed carbon dioxide ("CO2") and other greenhouse gases, including methane, to be a danger to public health, which is leading to regulation of greenhouse gases in a manner similar to other pollutants. For example, the EPA finalized amendments to the NSPS rules in June 2016 that focused on methane emissions from the oil and gas industry in June 2016. The rules imposed, among other things, new requirements for leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers and additional control requirements for gathering, boosting and compressor stations. In September 2018, the EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and compressor stations. On September 24, 2019 the EPA proposed reconsideration amendments to the NSPS that, among other things, would rescind the methane-specific requirements of the NSPS applicable to oil and gas production. The Bureau of Land Management (the "“BLM"”) also finalized similar methane and gas-capture rules for oil and gas operations on federal and tribal leases and certain committed state or private tracts in a federally approved unit or communitized agreement. In September 2018, the BLM published a final rule that revises the 2016 rules. The new rule, among other things, rescinds the 2016 rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels, and leak detection and repair. The new rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico ~~have~~ filed challenges to the 2018 rule in the United States District Court for the Northern District of California. On July 15, 2020, the court ruled in favor of plaintiffs and ordered that the 2018 Revision Rule be vacated. On July 21, 2020, the U.S.

The EPA already requires reporting of greenhouse gases, such as CO2 and methane, from operations. In 2014, 2017 and 2019, Colorado expanded its oil and gas air regulations, including the adoption of new and additional fugitive methane 20

Table of Contents

~~emission~~District ~~control~~Court ~~regulations.~~for Inthe ~~addition,~~District ~~in 2019 Colorado announced it's intention to implement state-level greenhouse gas reporting rules in 2020. The first phase~~ of ~~that~~Wyoming ~~initiative,~~lifted athe ~~new~~stay ~~rule requiring oil and gas operators to submit an annual emission inventory, was approved on December 19, 2019 and will go into effect~~ in ~~2020. The EPA has lowered~~ the ~~national~~case ~~ambient~~challenging ~~air quality standard ("NAAQS") for ozone pollution, which may require~~ the ~~oil~~2016 ~~and~~Waste ~~gas~~Prevention ~~industry to further reduce emissions of volatile organic compounds and nitrogen oxides~~Rule. ~~Colorado's~~On ~~ozone~~October ~~non-attainment~~8, ~~status was bumped-up from "marginal" to "moderate~~2020," inthe ~~early~~court ~~2016~~found ~~which~~that ~~triggered significant additional obligations for~~ the ~~State~~BLM ~~under~~exceeded ~~the~~its ~~Clean~~statutory ~~Air~~authority ~~Act~~ and ~~resulted~~acted arbitrarily in ~~additional~~promulgating ~~regulatory requirements for~~ the ~~oil~~2016 ~~and~~Waste ~~gas~~Prevention ~~industry~~Rule. OnThe ~~December~~court ~~26,~~ordered ~~2019 the EPA filed notice in the Federal Register~~ that ~~effective January 27, 2020~~ the ~~Denver~~rule ~~Metro/North Front Range NAA will~~ be ~~reclassified~~vacated, ~~again~~except ~~to from "moderate" to "serious". A "serious" classification triggers significant additional obligations~~ for ~~the~~certain ~~state~~severable ~~under~~provisions ~~the~~pertaining ~~CAA~~to ~~and~~royalty-free ~~will~~use ~~result~~of inproduction ~~new~~ and ~~more~~royalty ~~stringent~~rates ~~air~~on ~~quality~~competitive ~~control requirements becoming applicable to our operations~~leases. ~~this~~The ineffect ~~turn~~of ~~could~~the ~~result~~court’s inorder ~~significant~~is ~~costs~~to ~~and~~vacate ~~delays~~all inprovisions ~~obtaining~~of ~~necessary~~the ~~permits.~~Waste ~~These~~Prevention ~~state~~Rule ~~and~~pertaining ~~federal~~to ~~regulations may increase~~ the ~~costs~~loss of ~~compliance~~gas ~~for~~through ~~some~~venting, ~~facilities we own or operate~~flaring, and ~~federal~~leaks, and ~~state~~to ~~regulatory~~reinstate ~~agencies~~BLM ~~can~~Notice ~~impose~~to ~~administrative,~~Lessees ~~civil and criminal penalties for non~~NTL-~~compliance~~4A with ~~air~~respect ~~permits~~to orventing, ~~other~~flaring, ~~requirements of the Federal Clean Air Act~~ and ~~associated~~avoidably/unavoidably ~~state~~lost ~~laws and regulations~~determinations.

~~Colorado~~The SBEPA ~~19-181~~already ~~also~~ requires reporting of greenhouse gases, ~~among~~such ~~other~~as ~~things~~CO2 and methane, from operations. In 2014, 2017, 2019 and 2020, Colorado expanded its oil and gas air regulations, including the adoption of a new state-level emission inventory requirement for oil and gas operations that includes reporting of greenhouse gases. Additional oil and gas-related air quality rulemakings are scheduled for February and December of 2021. In 2019, the ~~Air~~Colorado ~~Quality~~legislature ~~Control~~passed ~~Commission~~House ~~("AQCC")~~Bill ~~adopt~~19-1261 ~~additional~~which ~~rules~~directs Colorado to ~~minimize~~reduce greenhouse gas emissions of26% ~~methane~~by ~~and~~2025, ~~other~~50% ~~hydrocarbons~~by 2030 and ~~nitrogen~~90% ~~oxides~~by 2050 from ~~the~~2005 ~~entire~~levels. We anticipate that the oil and gas ~~fuel~~industry ~~cycle.~~will ~~The~~be ~~AQCC~~significantly ~~anticipates~~targeted ~~holding~~in ~~several~~these ~~rulemakings~~efforts ~~over~~to reduce greenhouse gas emissions in the ~~next~~State ~~several~~of ~~years~~Colorado. toThe ~~implement~~EPA has lowered the ~~requirements~~national ofambient SBair ~~19-181~~quality standard (“NAAQS”) for ozone pollution, ~~including~~which amay ~~rulemaking~~require the oil and gas industry to ~~require~~further ~~continuous~~reduce ~~emission~~emissions ~~monitoring~~of ~~equipment~~volatile atorganic ~~oil~~compounds and ~~gas~~nitrogen ~~facilities~~oxides. InEffective ~~December~~January ~~2019~~27, 2020, the ~~AQCC~~Denver ~~held~~Metro/North Front Range NAA was reclassified again to from “moderate” to “serious”. The “serious” classification triggered significant additional obligations for the ~~first~~state ofunder ~~several~~the ~~rulemakings~~CAA ~~that~~and ~~are~~will ~~anticipated~~result in new and more stringent air quality control requirements becoming applicable to our operations as anew ~~result~~rules ofare SBpromulgated ~~19-181~~to meet these new requirements. AsBased ~~part~~on ofcurrent ~~that~~air ~~rulemaking~~quality monitoring data, it is expected that the ~~AQCC~~Denver ~~adopted~~Metro/North ~~significant~~Front Range NAA will be further reclassified to “severe” status in 2021 or 2022. This will trigger additional obligations for the state under the CAA and could result in new ~~emission~~and more stringent air quality control requirements, which may in turn result in significant costs, and delays in obtaining necessary permits applicable to ~~oil~~our operations. These state and ~~gas~~federal ~~operations~~regulations may increase the costs of compliance for some facilities we own or operate, ~~including~~and federal and state regulatory agencies can impose administrative, civil and criminal penalties for ~~example,~~non-compliance ~~hydrocarbon~~with ~~liquids~~air ~~unloading~~permits ~~control~~or other requirements ~~and~~of ~~increased~~the ~~LDAR~~Federal ~~frequencies~~Clean ~~for~~Air ~~facilities~~Act inand ~~certain~~associated ~~proximity~~state tolaws ~~occupied~~and ~~areas~~regulations.

~~State-level~~Colorado ~~rules~~SB ~~applicable~~19-181 toalso ~~our~~requires, ~~operations~~among ~~include~~other ~~regulations~~things, ~~imposed~~that by the ~~AQCC,~~Air ~~including~~Quality ~~stringent~~Control ~~requirements~~Commission ~~relating~~(“AQCC”) toadopt ~~monitoring,~~additional ~~recordkeeping~~rules ~~and~~to ~~reporting~~minimize ~~matters.~~emissions ~~In October 2019, the Colorado Department~~ of ~~Public~~methane ~~Health~~ and ~~Environment~~other ~~("CDPHE")~~hydrocarbons ~~published~~and anitrogen ~~human~~oxides ~~health~~from ~~risk~~the ~~assessment~~entire ~~for~~ oil and gas ~~operations~~fuel incycle. ~~Colorado,~~The ~~which~~AQCC ~~used~~conducted oil and gas-related ~~emission~~air ~~data~~quality torulemakings ~~model~~in ~~possible~~2020 ~~human~~related ~~exposure~~to ~~and~~the ~~found~~control ~~a possibility~~ of ~~negative~~emissions ~~health~~from ~~impacts~~natural atgas-fired ~~distances~~reciprocating upinternal tocombustion 2engines,~~000~~ ~~feet~~oil ~~away~~and ~~under~~gas ~~worst~~flowback ~~case conditions. In response~~tanks, ~~the~~and ~~COGCC~~ambient ~~announced~~monitoring ~~that~~of itemissions ~~will~~at ~~more~~oil ~~rigorously~~and ~~scrutinize~~gas ~~permit~~facilities ~~applications~~that ~~for~~go ~~wells~~through ~~within~~pre-production ~~2,000~~operations. ~~feet~~Additional offuture arulemaking ~~building~~will ~~unit,~~include ~~work~~discussion ~~with~~of ~~CDPHE~~continuous toemissions ~~obtain~~monitoring ~~better~~equipment ~~site-specific~~at ~~data on~~ oil and gas ~~emissions~~facilities, ~~and~~use ~~consider~~of ~~the~~natural ~~resulting~~gas-driven ~~data~~pneumatic ~~for~~controllers ~~possible~~and ~~future~~oil ~~rulemaking~~and gas-related greenhouse gas emissions.

Hydraulic Fracturing. Our completion operations are subject to regulation, which may increase in the short or long-term. The well completion technique known as hydraulic fracturing is used to stimulate production of natural gas and oil and has come under increased scrutiny by the environmental community, as well as local, state and federal jurisdictions. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into prospective rock formations at depth to stimulate oil and natural gas production. We use this completion technique on substantially all of our wells to obtain commercial production.

Under the direction of Congress, the EPA has undertaken a study of the effect, if any, of hydraulic fracturing on drinking water and groundwater and released its preliminary report in 2015, finding no systematic impact on groundwater resources. In its final report, issued in late 2016, EPA removed the conclusion of no systemic impact from the executive summary of the report, although it cited no new evidence to the contrary. In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. In December 2016, the EPA released a report titled "“Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources."” The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances. These and similar studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. Congress may consider legislation to amend the SDWA or the Toxic Substances Control Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Certain states, including Colorado, Utah and Wyoming, have already issued such disclosure rules. Several environmental groups have also petitioned the EPA to extend release reporting requirements under the Emergency Planning Community Right-to-Know Act to the oil and gas extraction industry and in 2015, EPA granted, in part, one of these petitions to add the oil and gas extraction industry to the list of industries required to report releases of certain "“toxic chemicals"” under the Toxic Release Inventory ("“TRI"”). On January 6, 2017, EPA issued a proposed rule to include natural gas processing facilities within the TRI program. In addition, the Department of the Interior finalized expanded or new regulations concerning the use of hydraulic fracturing on lands under its ~~jurisdiction, which includes some of the lands on which we conduct or plan to conduct operations. The BLM rescinded the rule~~

1921

Table of Contents

jurisdiction, which includes some of the lands on which we conduct or plan to conduct operations. The BLM rescinded the rule in December 2017; however, the BLM'’s rescission has been challenged by several states in the United States District Court of the District of Northern California. A federal district court in California granted BLM’s motion for summary judgement in March 2020, upholding the agency’s decision to rescind the Hydraulic Fracturing Rule. The plaintiffs in that case have appealed the California federal court’s decision to the U.S. Court of Appeals for the Ninth Circuit, where the case is pending.

InOn ~~Colorado~~January 20, ~~certain~~2021, ~~local~~the ~~jurisdictions~~Acting ~~imposed~~Secretary ~~moratoria~~of orthe ~~bans~~Interior onissued ~~hydraulic~~an ~~fracturing,~~order ~~all~~suspending for 60 days the authority of ~~which~~bureaus ~~have~~within ~~been~~the ~~invalidated~~Department of the Interior to issue fossil fuel authorizations, including new oil and gas leases and drilling permits on ~~appeal~~federal tolands ~~the~~and ~~Colorado~~in ~~Supreme~~offshore ~~Court~~waters. ~~Senate~~Additionally, ~~Bill~~on ~~19-181~~January ~~subsequently~~27, ~~authorized~~2021, ~~local~~President ~~jurisdictions~~Biden tosigned ~~approve~~an ~~the~~executive ~~siting~~order ofpausing ~~and~~leasing ~~regulate~~on ~~the~~federal ~~surface~~lands ~~impacts~~and ~~from~~in ~~oil~~offshore ~~and~~waters ~~gas~~pending ~~development~~completion ~~and~~of toa ~~adopt~~comprehensive ~~regulations~~review and ~~impose~~reconsideration ~~conditions~~of ~~more~~federal ~~stringent~~oil ~~than~~and ~~state~~gas ~~requirements~~permitting and leasing practices. ItThe ~~remains~~executive ~~unclear~~order ~~whether~~does ~~local~~not ~~governments~~specify ~~will~~a ~~attempt~~timeframe toby ~~use~~which this ~~new~~review ~~authority~~must tobe ~~restrict~~completed. ~~hydraulic~~The ~~fracturing~~executive ororder ~~oil~~ and ~~gas~~its ~~development~~implementation orare ~~whether~~currently ~~such~~being ~~action~~challenged ~~would~~in bethe ~~lawful~~United ~~under~~States SBDistrict ~~19-181~~Court ~~and~~for ~~Colorado~~the ~~Supreme~~District ~~Court~~of ~~precedent~~Wyoming.

~~Climate Change.~~ In ~~June 2014~~Colorado, ~~the U.S. Supreme Court upheld a portion of the EPA's greenhouse gas regulatory program for~~ certain ~~major~~local ~~sources~~jurisdictions inimposed ~~the~~moratoria ~~Utility~~or ~~Air~~bans ~~Regulatory~~on ~~Group~~hydraulic ~~v. EPA case. The EPA has finalized significant new rules to curb carbon emissions from power plants and other industrial activities~~fracturing, ~~known~~all asof ~~the~~which ~~Clean~~have ~~Power~~been ~~Plan~~invalidated, ~~which~~including inon ~~February~~appeal ~~2016~~to ~~was stayed by~~ the ~~U.S.~~Colorado Supreme Court. InSenate ~~March~~Bill ~~2017,~~19-181 ~~President Trump signed the Executive Order on Energy Independence which, among other things, called for a review of the Clean Power Plan. The EPA~~ subsequently ~~published~~authorized alocal ~~proposed~~jurisdictions ~~rule~~ to ~~repeal~~approve the ~~Clean~~siting ~~Power~~of ~~Plan~~and inregulate ~~October 2017. In August 2018, EPA proposed~~ the ~~Affordable~~surface ~~Clean~~impacts ~~Energy ("ACE") rule, which establishes emission guidelines for states to develop plans to address greenhouse gas emissions~~ from ~~existing~~oil ~~coal-fired power plants. The ACE rule was finalized on June 19, 2019~~ and ~~replaced~~gas ~~the~~development ~~Clean Power Plan. Certain environmental groups are agitating for scaling back, or eliminating, fossil fuel extraction~~ and ~~use, including efforts~~ to ~~convince~~adopt ~~policy-makers~~regulations ~~that the majority of known oil~~ and ~~gas~~impose ~~reserves~~conditions ~~must~~more ~~never~~stringent ~~leave~~than ~~the~~state ~~ground~~requirements. ~~These groups are mobilizing around a movement for global divestment from fossil fuel companies, which, if effective, could affect the market for our securities.~~ In ~~addition, in December 2015~~ the ~~United~~wake ~~States~~of ~~reached~~Senate ~~agreement~~Bill ~~during the United Nations climate change conference in Paris to make a 26~~19-~~28%~~181 ~~reduction~~several inlocal ~~its~~jurisdictions ~~greenhouse~~established ~~gas~~temporary ~~emissions~~moratoriums, byciting ~~2025 against~~ a ~~2005~~need ~~baseline.~~for ~~In June 2017, President Trump announced that~~ the ~~United~~rules ~~States~~required ~~would~~by ~~initiate~~Senate ~~the~~Bill ~~formal~~19-181 ~~process~~ to ~~withdraw~~be ~~from the Paris Agreement~~enacted. ~~Per~~It ~~the~~remains ~~terms~~unclear ofwhether ~~the~~local ~~Paris~~governments ~~Agreement,~~will aattempt country cannot give notice of withdrawal from the agreement before three years of its start date in the relevant country, which was on November 4, 2016 in the case of the United States. On November 4, 2019, President Trump's administration gave a formal notice of intention to ~~withdraw,~~use ~~which~~this ~~takes~~new 12authority ~~months~~ to ~~take~~more ~~effect.~~permanently ~~Potential~~restrict ~~future~~hydraulic ~~laws,~~fracturing ~~regulations~~ or ~~even~~oil ~~litigation~~and ~~addressing greenhouse~~ gas ~~emissions~~development ~~could impact our business by limiting emissions of methane, restricting the flaring~~ or ~~venting~~whether ofsuch ~~natural~~action ~~gas,~~would orbe bylawful ~~reducing~~under ~~demand~~SB ~~for~~19-181 ~~oil~~and orColorado ~~natural~~Supreme ~~gas~~Court precedent.

Climate Change. In June 2014, the U.S. Supreme Court upheld a portion of the EPA’s greenhouse gas regulatory program for certain major sources in the Utility Air Regulatory Group v. EPA case. The EPA has finalized significant new rules to curb carbon emissions from power plants and other industrial activities, known as the Clean Power Plan, which in February 2016 was stayed by the U.S. Supreme Court. In March 2017, President Trump signed the Executive Order on Energy Independence which, among other things, called for a review of the Clean Power Plan. The EPA subsequently published a proposed rule to repeal the Clean Power Plan in October 2017. In August 2018, EPA proposed the Affordable Clean Energy (“ACE”) rule, which establishes emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. The ACE rule was finalized on June 19, 2019 and replaced the Clean Power Plan. On January 19, 2021 the United States Court of Appeals for the District of Columbia Circuit vacated the ACE rule and remanded to the EPA to consider a new regulatory framework to replace the rule. Certain environmental groups are agitating for scaling back, or eliminating, fossil fuel extraction and use, including efforts to convince policy-makers that the majority of known oil and gas reserves must never leave the ground. These groups are mobilizing around a movement for global divestment from fossil fuel companies, which, if effective, could affect the market for our securities. In addition, in December 2015 the United States reached agreement during the United Nations climate change conference in Paris to make a 26-28% reduction in its greenhouse gas emissions by 2025 against a 2005 baseline. In June 2017, President Trump announced that the United States would initiate the formal process to withdraw from the Paris Agreement. Per the terms of the Paris Agreement, a country cannot give notice of withdrawal from the agreement before three years of its start date in the relevant country, which was on November 4, 2016 in the case of the United States. On November 4, 2019, President Trump’s administration gave a formal notice of intention to withdraw, which began a 12 month process to formally withdraw on November 4, 2020. On January 20, 2021, President Biden signed an executive order recommitting the United States to the Paris Agreement. Potential future laws, regulations or even litigation addressing greenhouse gas emissions could impact our business by limiting emissions of methane, restricting the flaring or venting of natural gas, or by reducing demand for oil or natural gas.

Homeland Security. Legislation continues to be introduced in Congress, and development of regulations continues in the Department of Homeland Security and other agencies, concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations but cost of compliance cannot be accurately estimated at this time.

Cybersecurity. Cybersecurity has been a topic of increased focus, and we have implemented several cybersecurity measures, including an emergency response plan, annual employee training, penetration tests, internal vulnerability testing, Supervisory Control and Data Acquisition ("“SCADA"”) protection and ~~firewall~~other security technology upgrades. We ~~have~~utilize ~~installed~~ a comprehensive software package to track and document our cybersecurity initiatives which are reviewed regularly by the Executive Committee and ~~Board~~annually onby athe ~~regular basis~~Board. Our cybersecurity initiatives are an ~~increasingly~~ important function of our Information Technology and Legal Departments. Presently, it is not possible to accurately estimate the costs we could incur to respond to a cyber attack, but such expenditures could be substantial.

Table of Contents

Other Regulation of the Oil and Gas Industry

Our operations are subject to other types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, bonds securing plugging, abandonment and reclamation obligations, and reports concerning our operations. Most states, and some counties and municipalities also regulate one or more of the following:

• the location of wells and surface facilities;

• the noise, traffic and light from the location;

• the method of drilling and casing wells;

• the rates of production or "“allowables"”;

• the surface use and restoration of properties upon which wells are drilled;

• wildlife management and protection;

• the protection of archaeological and paleontological resources;

• the plugging and abandoning of wells; and

• notice to, and consultation with, surface owners and other third parties.

Table of Contents

State laws regulate the size and shape of drilling and spacing units or proration units governing well density and location, as well as the pooling of oil and natural gas properties. Some states provide statutory mechanisms for compulsory pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, compulsory pooling or unitization may be implemented by third parties and subject our interest to third party operations. While not currently an issue in Colorado, other states establish maximum rates of production from oil and natural gas wells and impose requirements regarding ratable takes by purchasers of production. Such laws and regulations, if adopted in Colorado, might limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, our production is generally subject to multiple layers of severance and/or ad valorem taxation by states, counties and special taxing districts.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission ("“FERC"”) has jurisdiction over the transportation and sale or resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for "“first sales"” of domestic natural gas, which include all sales of our own production.

FERC also regulates interstate natural gas transportation rates and service conditions pursuant to the Natural Gas Act, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Interstate gas pipeline companies are required to provide nondiscriminatory, non-preferential transportation services to producers, marketers and other shippers regardless of whether such shippers are affiliated with an interstate pipeline company, and pursuant to such orders, regulations, and rules, interstate gas pipeline companies are required to file the tariff rates and other terms and conditions of such services with FERC.

The Energy Policy Act of 2005 (the "“EPAct 2005"”) was signed into law in August 2005. The EPAct 2005 amends the Natural Gas Act to make it unlawful for "“any entity"”, including otherwise non-jurisdictional producers, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. The EPAct 2005 also gives FERC authority to impose civil penalties for violations of the Natural Gas Act or Natural Gas Policy Act up to $1 million per day per violation. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gathering or production, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted "“in connection with"” natural gas sales, purchases or transportation subject to FERC jurisdiction, thus reflecting a significant expansion of FERC'’s enforcement authority.

FERC'’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach pursued by FERC and Congress over the past few decades will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes may have on our natural gas-related activities.

Transportation and safety of natural gas is also subject to regulation by the U.S. Department of Transportation, through its Pipeline and Hazardous Materials Safety Administration, under the Natural Gas Pipeline Safety Act of 1968, as amended, which imposes safety requirements on the design, construction, operation, and maintenance of interstate natural gas transmission facilities, the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The failure to comply with these rules and regulations can result in substantial penalties.

Table of Contents

which imposes safety requirements on the design, construction, operation, and maintenance of interstate natural gas transmission facilities, the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The failure to comply with these rules and regulations can result in substantial penalties.

Employees

As of February 4, ~~2020~~2021, we had ~~155~~124 employees of whom 9771 work in our Denver office and 5853 work in our field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are good.

Offices

As of December 31, ~~2019~~2020, we ~~leased~~have 79,279 square feet of leased office space for our principal office in Denver, Colorado at 555 17th Street, which expires in April 2028. ~~Due~~We toalso ~~the~~have ~~Merger~~15,160 ~~we acquired 23,363~~ square feet of remaining leased office space ~~from Fifth Creek~~ in Greenwood Village, Colorado, which was acquired in the 2018 Merger and extends through July 2023. We also own a field office in Greeley, Colorado and a field office in Hereford, Colorado. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed.

Table of Contents

additional leased space if needed.

Annual CEO Certification

As required by New York Stock Exchange rules, on ~~May~~April 630, ~~2019~~2020 we submitted an annual certification signed by our Chief Executive Officer certifying that he was not aware of any violation by us of New York Stock Exchange corporate governance listing standards as of the date of the certification.

Item 1A. Risk Factors.

Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only risks facing the Company. Additional risks not presently known to us or that we currently consider immaterial also may adversely affect our Company.

Risks Related to the Merger and the Prepackaged Plan

The Merger may not be completed and, if it is completed, will subject our stockholders to certain risks and uncertainties. We are also subject to numerous risks associated with the Prepackaged Plan.

Key risks associated with the Merger and the Prepackaged Plan are described below, and are discussed in the “Risk Factors” section of Bonanza Creek’s Registration Statement on Form S-4 filed with the SEC in connection with the Merger:

•Because the market price of Bonanza Creek common stock will fluctuate, HighPoint stockholders and holders of HighPoint equity awards cannot be sure of the value of the shares of Bonanza Creek common stock they will receive, in the aggregate, in the Merger. In addition, because the number of shares of Bonanza Creek common stock to be issued in the Merger is fixed, the number of shares of Bonanza Creek common stock to be received, in the aggregate, by HighPoint stockholders and holders of HighPoint equity awards in the Merger will not change between now and the time the Merger is completed to reflect changes in the trading prices of Bonanza Creek common stock or HighPoint common stock.

•HighPoint stockholders, as of immediately prior to the Merger, will have reduced ownership in the combined company.

•Bonanza Creek and HighPoint must obtain certain regulatory approvals and clearances to consummate the Merger, which, if delayed, not granted or granted with unacceptable conditions, could prevent, substantially delay or impair consummation of the Merger, result in additional expenditures of money and resources or reduce the anticipated benefits of the Merger.

Table of Contents

•The Merger is subject to a number of conditions to the obligations of both Bonanza Creek and HighPoint to complete the Merger, which, if not fulfilled, or not fulfilled in a timely manner, may delay completion of the Merger or result in termination of the Merger Agreement.

•The Merger Agreement subjects HighPoint to restrictions on its business activities prior to the effective time of the Merger.

•The Merger Agreement limits HighPoint’s ability to pursue alternatives to the Merger, may discourage other companies from making a favorable alternative transaction proposal and, in specified circumstances, could require HighPoint to pay a termination fee to Bonanza Creek.

•Failure to complete the Merger out of court or in connection with the Prepackaged Plan could negatively impact HighPoint’s stock price and have a material adverse effect on its results of operations, cash flows and financial position.

•The transaction support agreement relating to the Merger may be terminated.

•Litigation relating to the merger could result in an injunction preventing the completion of the Merger and/or substantial costs to HighPoint or the combined company.

•The Prepackaged Plan may have a material adverse effect on HighPoint’s operations.

•Even if HighPoint receives all necessary acceptances and meets all other conditions precedent for the Prepackaged Plan to become effective, the HighPoint board may, for fiduciary or other reasons on behalf of HighPoint, choose not to commence the HighPoint Chapter 11 cases and the transactions, including the Merger, may not be completed.

•The Bankruptcy Court may not confirm the Prepackaged Plan or may require HighPoint to re-solicit votes with respect to the Prepackaged Plan.

•The Prepackaged Plan may be confirmed over the objection of the HighPoint stockholders.

•Even if HighPoint receives all acceptances necessary for the Prepackaged Plan to become effective, HighPoint may fail to meet all conditions precedent to effectiveness of the Prepackaged Plan.

•Other parties in interest might be permitted to propose alternative plans of reorganization that may be less favorable to certain of HighPoint’s constituencies than the Prepackaged Plan.

•HighPoint cannot predict the amount of time that it would spend in bankruptcy for the purpose of implementing the Prepackaged Plan and a lengthy bankruptcy proceeding could disrupt HighPoint’s business as well as impair the prospect for reorganization on the terms contained in the Prepackaged Plan.

•HighPoint may seek to amend, waive, modify or withdraw the Prepackaged Plan at any time prior to the confirmation of the Prepackaged Plan.

Risks Related to our Senior Notes and Credit Facility

Our potential inability to comply with the financial covenants in our Credit Facility have raised substantial doubt about our ability to continue as a going concern. We may not be able to generate enough cash flow to meet our debt obligations.

We have financial covenants associated with our Credit Facility that are measured each quarter. As discussed in the “Going Concern” section in Note 2 of the notes to the consolidated financial statements, based on our forecasted cash flow analysis for the twelve month period subsequent to the date of this filing, it is probable we will breach a financial covenant under our Credit Facility in the third quarter of 2021. However, timing could change as a result of changes in our business and the overall economic environment. Violation of any covenant under the Credit Facility provides the lenders with the option to accelerate the maturity of the Credit Facility, which carries a balance of $140.0 million as of December 31, 2020. This would, in turn, result in cross-default under the indentures to our senior notes, accelerating the maturity of the senior notes, which have a principal balance outstanding of $625.0 million as of December 31, 2020. We do not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default. These conditions and events raise substantial doubt about our ability to continue as a going concern.

Table of Contents

In addition, our independent auditor has included an explanatory paragraph regarding our ability to continue as a “going concern” (“going concern opinion”) in its report in this Annual Report on Form 10-K, which would accelerate a default under our Credit Facility to the filing date of this Annual Report on Form 10-K. However, we obtained a waiver from our lenders removing the default associated with this going concern opinion.

In response to these conditions, we have taken various steps to preserve our liquidity including (1) deferring drilling and completion activity starting in May 2020 for the foreseeable future, (2) continuing to focus on reducing our operating and overhead costs, and (3) continuing to manage our hedge portfolio. We could remain in compliance with the financial covenant if we (1) negotiate a waiver of the financial covenant with the lenders, (2) negotiate more flexible financial covenants, or (3) refinance the Credit Facility or senior notes. However, the availability of capital funding that would allow us to refinance the debt on acceptable terms has substantially diminished. In addition, we entered into a Merger Agreement with Bonanza Creek on November 9, 2020, pursuant to which HighPoint’s debt will be restructured and HighPoint will merge with a wholly owned subsidiary of Bonanza Creek, with HighPoint continuing its existence as the surviving company following the merger and continuing as a wholly owned subsidiary of Bonanza Creek. See “Items 1 and 2 Business and Properties - Business - Significant Business Developments” for additional information. However, the Merger has not yet closed and the closing is subject to numerous conditions. See “Risks Related to the Merger” above and “Items 1 and 2 Business and Properties - Business - Significant Business Developments” for additional information.

At December 31, 2020, we had cash and cash equivalents of $24.7 million and $140.0 million outstanding under the Credit Facility. At December 31, 2019, we had cash and cash equivalents of $16.4 million and $140.0 million outstanding under our Credit Facility. As part of our regular semi-annual redeterminations, the elected commitment amount on our Credit Facility was reduced to $300.0 million on May 21, 2020 and to $185.0 million on November 3, 2020. Our available borrowing capacity as of December 31, 2020 was $24.0 million, after taking into account $21.0 million of outstanding irrevocable letters of credit, which were issued as credit support for future payments under contractual obligations.

If we do not generate enough cash flow from operations to satisfy our debt obligations, and the Merger does not close, we may have to undertake one or more alternative financing plans, such as:

•refinancing or restructuring our debt;

•filing for Chapter 11 bankruptcy;

•selling assets;

•reducing or delaying capital investments; or

•seeking to raise additional capital.

However, any alternative financing plans that we undertake may not be completed in a timely manner or at all, and even if completed may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the senior notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

Our debt could have important consequences. For example, it could:

•increase our costs of doing business;

•increase our vulnerability to general adverse economic and industry conditions;

•limit our ability to fund future capital expenditures and working capital, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt;

•limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•impair our ability to obtain additional financing in the future; and

•place us at a competitive disadvantage compared to our competitors that have less debt.

Our customers, suppliers, vendors, employees and other third parties with whom we do business may react negatively to the substantial doubt about our ability to continue as a going concern.

It may be more difficult to enter into contractual arrangements with our customers who purchase our oil and gas production as well as with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. We may not be able to establish strategic relationships, which may take the form of joint ventures with other third

Table of Contents

parties. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

Risks Related to the Oil and Natural Gas Industry and Our Business

The COVID-19 pandemic and recent developments in the oil and gas industry have and could continue to materially adversely affect our operations during 2021 and possibly beyond.

In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus (the “COVID-19 pandemic”). As the virus spread, global economic activity began to slow, resulting in a decrease in demand for oil and natural gas. In response, OPEC+ initiated discussions to reduce production to support energy prices. With OPEC+ unable to agree on cuts, energy prices declined sharply during the first half of 2020. While prices partially recovered during the second half of 2020, uncertainties related to the demand for oil and natural gas remain as the COVID-19 pandemic continues to impact the world economy. The impacts of substantially lower oil, natural gas and NGL prices on our results of operations for the year ended December 31, 2020 were mostly mitigated by hedges in place on 91% of our oil production and 33% of our natural gas production. However, the economics of our existing wells and planned future development were adversely affected, which led to impairments of our proved and unproved oil and gas properties, reductions to our oil and gas reserve quantities and reductions to the borrowing capacity on our Credit Facility. There is uncertainty around the timing of recovery of the global economy from COVID-19 and its effects on the supply and demand for oil, natural gas and NGLs. If energy prices do not improve, our capital availability, liquidity and profitability will continue to be adversely affected, particularly after our current hedges are realized in 2021.

A U.S. and global economic downturn due to the COVID-19 pandemic or other global crisis could have a material adverse effect on our business and operations.

Any or all of the following may occur as a result of an economic downturn:

•The economic slowdown could lead to continued lower demand for oil and natural gas by individuals and industries, which in turn could result in continued lower prices for the oil and natural gas sold by us, lower revenues and possibly losses.

•The lenders under our Credit Facility may become more restrictive in their lending practices or unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and possibly losses.

•We may be unable to obtain additional debt or equity financing, which would require us to continue to limit our capital expenditures and other spending. This would lead to lower production levels and reserves than if we were able to spend more than our cash flow. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.

•The losses incurred by financial institutions and the insolvency of some financial institutions heightens the risk that a counterparty to our hedge arrangements could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy or being placed in conservatorship or receivership may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales. As a result, our financial condition could be materially adversely affected.

•Our Credit Facility bears floating interest rates based on the London Interbank Offer Rate (“LIBOR”). LIBOR will no longer be used as a reference index for determining interest rates under credit arrangements starting in 2023. The elimination of LIBOR may cause us to incur increased interest expense.

•Our Credit Facility requires the lenders to redetermine our borrowing base semi-annually. Our borrowing capacity was reduced from $500 million to $250 million in May 2020 and from $250 million to $185 million in November 2020. The redeterminations are based on our proved reserves and hedge position based on price assumptions that our lenders require us to use to calculate reserves pursuant to the Credit Facility. The lenders could reduce their price assumptions used to determine reserves for calculating our borrowing base due to lower commodities and futures prices and our borrowing base could be reduced further. This would further reduce our funds available to borrow. In addition, the

Table of Contents

lenders can request an interim redetermination during each six month period which could reduce the funds available to borrow under our Credit Facility.

•Bankruptcies of financial institutions or illiquidity of money market funds may limit or delay our access to our cash and cash equivalent deposits, causing us to lose some or all of those funds or to incur additional costs to borrow funds needed on a short-term basis that were previously funded from our money market deposits.

•Bankruptcies of purchasers of our oil and natural gas could lead to the delay or failure of us to receive the revenues from those sales.

Oil and gas prices are volatile and changes in prices can significantly affect our financial results and estimated proved oil and gas reserves.

Our revenue, profitability and cash flow depend upon the prices for oil, natural gas and NGLs. The markets for these commodities are very volatile, based on supply and demand, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in oil, natural gas and NGL prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil, natural gas and NGLs may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

• the global demand for oil, natural gas and NGLs;

• domestic and foreign governmental regulations;

• variations between product prices at sales points and applicable index prices;

• political and economic conditions in oil producing countries, including the Middle East and South America;

• the ability and willingness of members of ~~the Organization of Petroleum Exporting Countries ("~~OPEC")+ ~~and other oil-producing countries~~ to agree to and maintain oil price and production controls;

• weather conditions;

• technological advances affecting energy consumption;

• national and global economic conditions;

• proximity and capacity of oil and gas pipelines, refineries and other transportation and processing facilities;

• the price and availability of alternative fuels; and

• the strength of the U.S. dollar compared to other currencies.

Lower oil, natural gas and NGL prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore the quantity and the estimated present value of our reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration or development results deteriorate, successful efforts accounting rules may require us to write down or impair, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management'’s plans change with respect to those assets.

~~Oil~~As ~~prices~~described ~~declined~~above, ~~significantly~~oil, innatural agas ~~number~~and ofNGL ~~recent~~prices ~~periods,~~declined ~~including~~significantly ~~the~~during ~~fourth~~2020 ~~quarter~~due ofto ~~2018.~~OPEC+ ~~Natural~~unable ~~gas~~to ~~and~~agree ~~NGL~~on ~~prices~~cuts ~~have~~and ~~also~~the ~~fallen~~COVID-19 ~~significantly in some recent periods~~pandemic. These decreases have increased the volatility and amplitude of the other risks facing us as described in this report and have impacted our business and financial condition. If oil prices decrease from current levels, our planned drilling projects may become uneconomic, which could affect future drilling plans and growth rates. Low commodity prices impact our revenue, which we partially mitigate with our hedging program. Continued low commodity prices make it more challenging to hedge production at higher price levels.

~~Our~~If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time or cause us to change drilling ~~efforts~~plans and/or ~~our~~forego ~~well~~lease ~~operations~~renewals ~~may~~or ~~not~~cause significant decreases in property market values, we may be ~~profitable~~required orto ~~achieve~~take an impairment against the carrying values of our ~~targeted~~proved ~~returns~~and/or unproved properties.

22Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors such as lease expirations, changes in drilling plans and adverse drilling results, we may be required to take an impairment against the carrying value of our properties. An impairment constitutes a non-cash charge to earnings. For the year ended December 31, 2020, we recorded non-cash impairment charges of approximately $1.3 billion on proved and unproved oil and gas properties, and if market or other economic conditions deteriorate further or if oil and gas prices continue to decline, we may incur additional impairment charges, which may have a material adverse effect on our results of operations.

Table of Contents

Our drilling efforts and our well operations may not be profitable or achieve our targeted returns.

Drilling for oil, natural gas and NGLs may result in unprofitable efforts from wells that are productive but do not produce sufficient commercial quantities to cover drilling, operating and other costs. In addition, even a commercial well may have production that is less, or costs that are greater, than we projected. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues, midstream constraints and for other reasons. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of unproved property or drilling a well, whether oil, natural gas or NGLs are present or may be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. Drilling results in some of our plays may be more uncertain than in other plays that are more mature and have longer established drilling and production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other formations to maximize recoveries will be ultimately successful when used in our prospects. As a result, we may incur future dry hole costs and/or impairment charges due to any of these factors.

We have acquired significant amounts of proved and unproved property in order to attempt to further our exploration and development efforts. Drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire proved and unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. We cannot guarantee that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that proved or unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, that we will recover all or any portion of our investment in such proved or unproved property or wells, or that we will succeed in bringing on additional partners.

Substantially all of our producing properties are located in the DJ Basin, making us vulnerable to risks associated with operating in one major geographic area.

Our operations are focused on the DJ Basin, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of oil, natural gas and NGLs produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production or interruption of transportation and processing, and any resulting delays or interruptions of production from existing or planned new wells.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business and the recording of proved reserves. Changes in the regulatory environment could have a material adverse effect on our business.

Our exploration, development, production and marketing operations are subject to extensive environmental regulation at the federal, state and local levels including those governing emissions to air, wastewater discharges, hazardous and solid wastes, remediation of contaminated soil and groundwater, protection of surface and groundwater, land reclamation and preservation of natural resources. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil, and criminal penalties, including the assessment of natural resource damages. Environmental and other governmental laws and regulations also increase the costs to plan, permit, design, drill, install, operate and abandon oil and natural gas wells and related facilities. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects, leading to delays. One of the first actions of the new Biden Administration was to suspend the processing of federal permits, followed by a 90-day hiatus of the federal leasing program.

The regulatory environment in which we operate is subject to frequent changes, often in ways that increase our costs and make it more difficult for us to obtain necessary permits in a timely manner. See "“Business and Properties-Operations-Environmental Matters and Regulation"” for a summary of certain environmental regulations that affect our business and related developments, including potential future regulatory developments.

~~Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.~~ 29

Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other

Table of Contents

~~professional~~Our ~~personnel~~success ~~remains~~depends ~~strong.~~on Ifkey wemembers ~~cannot~~of ~~retain~~ our ~~current~~management ~~personnel~~and ~~or attract additional experienced personnel,~~ our ability to ~~compete~~attract ~~could~~and beretain ~~adversely affected. Also, the loss of~~ experienced ~~personnel~~technical ~~could~~and ~~lead~~other toprofessional ~~a loss of technical expertise~~personnel.

Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

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 our production. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of our reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and refineries owned and operated by third parties. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and gas operations. In addition, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured or under-insured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities, including well stimulation and completion activities such as hydraulic fracturing, are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

• environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

• abnormally pressured or structured formations;

• mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

• fires, explosions and ruptures of pipelines;

• personal injuries and death; and

• natural disasters or other adverse weather conditions.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

• injury or loss of life;

• damage to and destruction of property and equipment;

• damage to natural resources due to underground migration of hydraulic fracturing fluids or other fluids or gases;

• pollution and other environmental damage, including spillage or mishandling of recovered hydrocarbons, hydraulic fracturing fluids and produced water;

• regulatory investigations and penalties;

• suspension of our operations; and

• repair and remediation costs.

We have elected, and may in the future elect, not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. For example, we do not carry business interruption insurance for these reasons. In addition, pollution and environmental risks generally are not fully insurable. Further, we could be unaware of a pollution event when it occurs and therefore be unable to report the event within the time period required under the relevant policy. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse effect on our production, revenues and results of operations and overall financial condition.

Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil, natural gas and NGL reserves.

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the development, production and acquisition of oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with cash generated by operations, sales of our equity and debt securities, proceeds from bank borrowings and sales of properties. Our cash flow from operations and access to capital is subject to a number of variables, including:

2430

Table of Contents

•have financed capital expenditures primarily with cash generated by operations, sales of our ~~proved~~equity ~~reserves;~~and debt securities, proceeds from bank borrowings and sales of properties. Our cash flow from operations and access to capital is subject to a number of variables, including:

•our ~~the~~proved ~~level of oil, natural gas and NGLs we are able to produce from existing wells~~reserves;

• the ~~prices~~level atof ~~which~~ oil, natural gas and NGLs we are ~~sold~~able to produce from existing wells;

• the ~~costs~~prices ~~required~~at towhich ~~operate~~oil, ~~production~~natural gas and NGLs are sold;

•the ~~our~~costs ~~ability~~required to ~~acquire,~~operate ~~locate and produce new reserves~~production;

•our ~~global~~ability ~~credit~~to acquire, locate and ~~securities~~produce ~~markets~~new reserves;

•global ~~the~~credit ~~ability~~ and ~~willingness~~securities ~~of lenders and investors to provide capital and the cost of that capital~~markets; ~~and~~

• the ~~interest~~ability ofand ~~buyers~~willingness inof ~~our~~lenders ~~properties~~ and ~~the~~investors ~~price~~to ~~they~~provide ~~are~~capital ~~willing~~and tothe ~~pay~~cost ~~for~~of ~~properties.~~that capital; and

~~If our revenues or~~ •the ~~borrowing~~interest ~~base under our Amended Credit Facility decreases as a result~~ of ~~lower~~buyers ~~oil, natural gas and NGLs prices, operating difficulties, declines~~ in ~~reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain~~ our ~~operations~~properties ~~at current or planned levels. We may, from time to time, need to seek additional financing. Our Amended Credit Facility~~ and ~~senior note indentures place certain restrictions on our ability to obtain new financing. There can be no assurance as to~~ the ~~availability or terms of any additional financing. Recent commodity~~ price ~~decreases~~they ~~have~~are ~~made~~willing itto ~~substantially~~pay ~~more difficult~~ for ~~us and other industry participants to raise capital, and will likely have an adverse effect on our borrowing base~~properties.

If ~~additional~~our ~~capital~~revenues isor ~~needed,~~the weborrowing ~~may~~base ~~not~~under beour ~~able~~Credit toFacility ~~obtain~~decrease ~~debt~~as ora ~~equity~~result ~~financing~~of onlower ~~terms~~oil, ~~favorable~~natural togas ~~us,~~and orNGLs atprices, ~~all.~~which Ifwas the ~~cash~~case ~~generated~~for byboth ~~operations~~semi-annual borrowing base redeterminations in 2020, operating difficulties, declines in reserves or ~~the~~for ~~amount~~any ~~available~~other ~~under~~reason, ~~our~~we ~~Amended~~may ~~Credit~~have ~~Facility~~limited isability ~~not~~to ~~sufficient~~obtain the capital necessary to ~~meet~~sustain our ~~capital~~operations ~~requirements~~at current or planned levels. We may, ~~the~~from ~~failure~~time to ~~obtain~~time, need to seek additional financing. ~~could~~Our ~~result~~Credit inFacility aand ~~curtailment~~senior ofnote indentures place certain restrictions on our ~~operations~~ability ~~relating~~to obtain new financing. There can be no assurance as to ~~exploration~~the ~~and~~availability ~~development~~or terms of ~~our~~any ~~prospects,~~additional ~~which~~financing. inRecent ~~turn~~commodity ~~could~~price ~~lead~~decreases tohave amade ~~possible~~it ~~loss~~substantially ofmore ~~properties~~difficult ~~and~~for aus ~~decline~~and inother ~~our~~industry ~~oil,~~participants ~~natural~~to ~~gas~~raise capital, and ~~NGLs~~will ~~reserves~~likely ascontinue ~~well~~to ashave ~~our~~an ~~revenues~~adverse ~~and~~effect ~~results~~on ofour ~~operations~~borrowing base.

Our future drilling plans were suspended in 2020 and continue to be suspended due to significant declines in commodity prices and a decrease in borrowing capacity on our Credit Facility. In addition, in November 2020 we entered into the Merger Agreement with Bonanza Creek, and that agreement restricts our near-term capital spending levels and does not allow for drilling or completion operations. Furthermore, if the Merger does not close as contemplated, we do not have assurance that we will have the capital availability to resume drilling and completion operations. This resulted in a reduction in our oil, natural gas and NGL reserves as of December 31, 2020 primarily due to removing all PUD reserves, as we are not reasonably certain the PUD reserves will be drilled within the five year development window at the time the applicable PUD reserve is booked. Continued delays in our development plans could lead to a possible loss of properties and additional declines in our oil, natural gas and NGLs reserves as well as our revenues and results of operations.

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

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil, natural gas and NGLs prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil, natural gas and NGLs from these or any other potential drilling locations. As such, our actual drilling activities may differ materially from those presently identified, which could adversely affect our business.

Competition in the oil and gas industry is intense, which may adversely affect our ability to succeed.

The oil and gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for, develop and produce oil, natural gas and NGLs, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies are able to pay more for producing oil, natural gas and NGLs properties and exploration and development prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies have a greater ability to continue exploration activities during periods of low oil, natural gas and NGLs market prices. Our larger or integrated competitors are better able than we are to absorb the burden of existing and any changes to federal, state, local and Native American tribal laws and regulations, which could adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial resources than many companies in our industry, we may be at a disadvantage in bidding for producing properties and exploration and development prospects.

~~The willingness and ability of our lenders to fund their lending obligations under our revolving Amended Credit Facility may be limited, which would affect our ability to fund our operations.~~31

Our Amended Credit Facility has commitments from 11 lenders. If credit markets become turbulent as a result of an economic downturn, increased regulatory oversight, lower commodity prices or other factors, our lenders may become more restrictive in their lending practices or may be unwilling or unable to fund their commitments, which would limit our access to capital to fund our capital expenditures, operations or meet other obligations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and potentially losses.

A U.S. and global economic downturn could have a material adverse effect on our business and operations.

Table of Contents

~~Any~~The orwillingness ~~all~~and ability of ~~the~~our ~~following~~lenders ~~may~~to ~~occur~~fund ~~if,~~their aslending aobligations ~~result~~under ofour aCredit ~~crisis~~Facility inmay ~~the~~be ~~global financial and securities markets~~limited, awhich ~~deterioration~~would inaffect ~~national~~our orability ~~global~~to ~~growth~~fund ~~prospects~~our ~~or other factors, an economic downturn occurs:~~operations.

•Our ~~The~~Credit ~~economic~~Facility ~~slowdown~~has ~~could~~commitments ~~lead~~from to11 ~~lower~~lenders. ~~demand~~If ~~for~~credit ~~oil~~markets ~~and~~become ~~natural~~more ~~gas~~turbulent byas ~~individuals~~a ~~and~~result ~~industries,~~of ~~which~~the incurrent ~~turn~~economic ~~could~~downturn, ~~result~~increased inregulatory oversight, lower commodity prices ~~for~~or ~~the~~other ~~oil~~factors, ~~and~~our ~~natural~~lenders ~~gas~~may ~~sold~~become bymore ~~us,~~restrictive ~~lower~~in ~~revenues~~their ~~and~~lending ~~possibly~~practices ~~losses.~~or ~~Significant~~may ~~recent~~be ~~commodity~~unwilling ~~price~~or ~~declines~~unable ~~have~~to ~~been~~fund ~~caused~~their incommitments, ~~part~~which bywould ~~concerns~~limit ~~about~~our ~~future~~access ~~global~~to ~~economic~~capital ~~growth~~to fund our capital expenditures, operations or meet other obligations. This ~~factor~~would ~~has~~limit atour ~~times~~ability ~~been~~to ~~exacerbated~~generate byrevenues ~~increases~~as inwell ~~oil~~as ~~and~~limit ~~gas~~our ~~supply~~projected ~~resulting~~production ~~from~~and ~~increases~~reserves ingrowth, ~~U.S.~~leading ~~oil~~to declining production and ~~gas~~potentially ~~production~~losses.

• The lenders under our Amended Credit Facility may become more restrictive in their lending practices or unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and possibly losses.

• We may be unable to obtain additional debt or equity financing, which would require us to limit our capital expenditures and other spending. This would lead to lower production levels and reserves than if we were able to spend more than our cash flow. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.

• The losses incurred by financial institutions and the insolvency of some financial institutions heightens the risk that a counterparty to our hedge arrangements could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy or being placed in conservatorship or receivership may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales. As a result, our financial condition could be materially adversely affected.

• Our credit facility bears floating interest rates based on the London Interbank Offer Rate ("LIBOR"). As banks were reluctant to lend to each other to avoid risk, LIBOR increased to unprecedented spread levels in 2008. Such increases caused and may in the future cause higher interest expense for unhedged levels of LIBOR-based borrowings. In addition, LIBOR may be eliminated in the near future as a reference index for determining interest rates under credit arrangements. The elimination of LIBOR may cause us to incur increased interest expense.

• Our credit facility requires the lenders to redetermine our borrowing base semi-annually. The redeterminations are based on our proved reserves and hedge position based on price assumptions that our lenders require us to use to calculate reserves pursuant to the credit facility. The lenders could reduce their price assumptions used to determine reserves for calculating our borrowing base due to lower commodities and futures prices and our borrowing base could be reduced. This would reduce our funds available to borrow. In addition, the lenders can request an interim redetermination during each six month period which could reduce the funds available to borrow under our credit facility.

• Bankruptcies of financial institutions or illiquidity of money market funds may limit or delay our access to our cash and cash equivalent deposits, causing us to lose some or all of those funds or to incur additional costs to borrow funds needed on a short-term basis that were previously funded from our money market deposits.

• Bankruptcies of purchasers of our oil and natural gas could lead to the delay or failure of us to receive the revenues from those sales.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these assumptions will materially affect the quantities of our reserves.

Underground accumulations of oil, natural gas and NGLs cannot be measured in an exact way. Oil, natural gas and NGLs reserve engineering requires estimates of underground accumulations of oil, natural gas and NGLs and assumptions concerning future oil, natural gas and NGLs prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate.

Our estimates of proved reserves are based on prices and costs determined at the date of the estimate. Any significant variance from these prices and costs could greatly affect our estimates of reserves. We prepare our own estimates of proved reserves, which are audited by independent third party petroleum engineers. Over time, our internal engineers may make material changes to reserves estimates taking into account the results of actual drilling, testing and production. For additional information about these risks and their impact on our reserves, see “Items 1 and 2. Business and Properties-Oil and Gas Data-Proved Reserves” and “Supplementary Information to Consolidated Financial Statements-Supplementary Oil and Gas Information (unaudited)-Analysis of Changes in Proved Reserves” in this Annual Report on Form 10-K.

Table of Contents

reserves, which are audited by independent third party petroleum engineers. Over time, our internal engineers may make material changes to reserves estimates taking into account the results of actual drilling, testing and production. For additional information about these risks and their impact on our reserves, see "Items 1 and 2. Business and Properties-Oil and Gas Data-Proved Reserves" and "Supplementary Information to Consolidated Financial Statements-Supplementary Oil and Gas Information (unaudited)-Analysis of Changes in Proved Reserves" in this Annual Report on Form 10-K.

At December 31, 2019, approximately 59% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $1.2 billion during the five years ending December 31, 2024. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC's reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, and we may therefore be required to downgrade to probable or possible any PUDs that are not developed within this five-year time frame.

Unless we replace our oil, natural gas and NGLs reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil, natural gas and NGL reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may be different than we have estimated and may change over time. Our future oil, natural gas and NGL reserves and production, and therefore our cash flow and income, are highly dependent upon our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers.

One of our strategies is to capitalize on opportunistic acquisitions of oil, natural gas and NGLs reserves. Our reviews of acquired properties are inherently incomplete, because it generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties and will sample the remaining properties for reserve potential. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties.

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

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of commodities, we currently, and will likely in the future, enter into hedging arrangements for a portion of our production revenues. Hedging arrangements for a portion of our production revenues expose us to the risk of financial loss in some circumstances, including when:

• there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;

• our production is less than we expect;

• there is a change in the mark to market value of our derivatives; or

• the counterparty to the hedging contract defaults on its contractual obligations.

In addition, these types of hedging arrangements limit the benefit we would receive from increases in commodities prices and may expose us to cash margin requirements if we hedge with counterparties who are not parties to our credit facility.32

Our counterparties are financial institutions that are lenders under our Amended Credit Facility or affiliates of such lenders. The risk that a counterparty may default on its obligations increases when overall economic conditions deteriorate. Losses resulting from adverse economic conditions or other factors may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving lower prices for our production. As a result, our financial condition could be materially adversely affected.

Table of Contents

~~Federal~~In ~~legislation~~addition, ~~may~~these ~~decrease~~types ~~our~~of ~~ability,~~hedging ~~and~~arrangements ~~increase~~limit the ~~cost,~~benefit we would receive from increases in commodities prices and may expose us to ~~enter~~cash ~~into~~margin requirements if we hedge ~~transactions~~with counterparties who are not parties to our Credit Facility.

~~The~~Our ~~Dodd-Frank~~counterparties ~~Wall~~are ~~Street~~financial ~~Reform~~institutions ~~and~~that ~~Consumer~~are ~~Protection~~lenders ~~Act~~under ~~("Dodd-Frank")~~our ~~was~~Credit ~~signed~~Facility ~~into~~or ~~law~~affiliates inof ~~July~~such ~~2010~~lenders. ~~Dodd-Frank~~The ~~regulates~~risk ~~derivative~~that ~~transactions,~~a ~~including~~counterparty ~~our~~may ~~commodity~~default ~~derivative~~on ~~swaps. We expect that Dodd-Frank and~~ its ~~implementing~~obligations ~~regulations~~increases ~~will~~when ~~increase~~overall ~~the~~economic ~~cost~~conditions todeteriorate. ~~hedge~~Losses asresulting afrom ~~result~~adverse ofeconomic ~~fewer~~conditions ~~counterparties~~or ~~being~~other infactors ~~the~~may ~~market~~affect ~~and~~ the ~~pass-through~~ability of ~~increased~~the ~~capital~~counterparties ~~costs~~to ofmeet ~~bank~~their ~~subsidiaries.~~obligations ~~The~~to ~~imposition~~us ~~of margin requirements or other restrictions~~ on ~~our~~hedge ~~hedging~~transactions, ~~activities~~which could ~~make~~reduce ~~hedging more expensive or impracticable. A reduction in~~ our ~~ability~~revenues tofrom ~~enter~~hedges ~~into~~at ~~hedging~~a ~~transactions~~time ~~would~~when ~~expose~~we usare toalso ~~additional~~receiving ~~risks~~lower ~~related~~prices tofor ~~commodity price volatility and impair~~ our ~~ability~~production. toAs ~~have certainty with respect to~~ a ~~portion~~result, of our ~~cash~~financial ~~flow,~~condition ~~which~~ could ~~lead~~be tomaterially ~~decreases~~adversely ~~in capital spending and, therefore, decreases in future production and reserves~~affected.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil, natural gas and NGLs sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil, natural gas and NGLs hedging arrangements expose us to credit risk in the event of nonperformance by counterparties. ~~An economic downturn and/or an extended period of low commodity prices would increase these risks.~~

We face risks related to rating agency downgrades.

If one or more rating agencies downgrades our outstanding debt, future debt issuance could become more difficult and costly. Also, we may be required to provide collateral or other credit support to certain counterparties, which would increase our costs and limit our liquidity.

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

As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain unauthorized access to sensitive information, acquire cash or other assets through theft or fraud or render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, corruption of data or misappropriation of assets. There can be no assurance that the procedures and controls we use to monitor and mitigate these risks will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, assets, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.

Land owner demands associated with previously divested wells in Wyoming could have adverse effects on our business.

In December 2015, the Wyoming Supreme Court issued its "Pennaco" decision, the essence of which is that parties to a contract, such as a surface use agreement, remain liable for the obligations under that agreement - even when the agreement and the underlying assets have been sold and assigned to a third party - unless the agreement contains express language releasing and discharging the original party upon such subsequent assignment.

Landowners across Wyoming are making Pennaco claims against companies that sold assets to other oil and gas companies that are now in default. To date, our exposure relates to coalbed methane ("CBM") leases and wells that we sold to entities which are now essentially defunct, if not in actual bankruptcy proceedings. These operators have defaulted on several annual surface use payments, as well as leaving more than 150 CBM wells acquired from us in non-producing (shut-in) status. We have been contacted by several large ranches or their attorneys demanding payment of amounts in arrears, and that we conduct the plugging of the wells and land reclamation. Each case entails determining what contractual obligations are imposed by the applicable surface use agreement, taking into account state and federal plugging and reclamation requirements.

We obtained orders from the Wyoming Oil & Gas Conservation Commission ("WOGCC") requiring two of the defaulting operators to "show cause" as to why the WOGCC should not authorize us to take over the wells in order to conduct plugging and reclamation operations. In response to these orders, we reached contractual agreements that provide us with the authority to plug and abandon any or all of the wells sold to those operators. We have negotiated settlement and release agreements with several ranches that require payments and scheduled plugging and reclamation activities. In certain cases, ranch owners have

Table of Contents

expressed interest in conversion of CBM wells to water wells. We are under no current WOGCC compulsion to plug wells. A substantial number of wells are federally-permitted, and the Company and the BLM have recently negotiated a plugging and reclamation schedule for these wells. During 2019, the Company plugged 53 wells and 3 wells were converted to water wells by the landowner. In 2020, the Company plans to plug and abandon an additional 65 wells.

We do not believe that resolving this matter will have a material financial impact. We believe that, if necessary, the currently identified roster of shut-in wells can be plugged and reclaimed at cost of approximately $15,000 per well. There is no assurance, however, that this issue will not expand to wells sold to other purchasers of Wyoming assets previously owned by us.

Risks Related to Our Common Stock

IfThe ~~we cannot meet the "~~price ~~criteria"~~of ~~for~~our ~~continued~~common ~~listing~~stock onhas ~~the~~been ~~NYSE,~~and ~~the NYSE~~ may ~~delist~~continue ~~our~~to ~~common~~be ~~stock~~highly volatile, which ~~could~~may ~~have~~make anit ~~adverse~~difficult ~~impact~~for onshareholders ~~the~~to ~~trading~~sell ~~volume,~~our ~~liquidity~~common ~~and~~stock ~~market~~when ~~price~~desired ofor ~~our~~at ~~common~~attractive ~~stock~~prices.

IfThe wemarket ~~do not maintain an average closing~~ price of ~~$1.00 or more for~~ our common stock ~~over~~is ~~any~~highly ~~consecutive~~volatile. 30Adverse ~~trading-day~~events ~~period,~~could ~~the~~trigger ~~NYSE~~a ~~may~~significant ~~delist~~decline ~~our~~in ~~common stock for failure to maintain compliance with~~ the ~~NYSE~~trading price ~~criteria~~of ~~listing~~our ~~standards.~~common Asstock, ~~of February 4~~including, ~~2020~~among others, ~~the~~unfavorable ~~average~~changes ~~closing~~in ~~price~~commodity ofprices ~~our~~or ~~common~~commodity ~~stock~~price ~~over~~expectations, ~~the~~adverse ~~immediately~~regulatory ~~preceding~~developments 30and ~~consecutive~~adverse ~~trading-day~~developments ~~period~~relating ~~was~~to $1the Merger.~~45.~~ ~~The~~Furthermore, ~~NYSE~~general ~~Listed~~market ~~Company~~conditions, ~~Manual~~including ~~sets~~the ~~out~~level ~~rules~~of, and ~~processes~~fluctuations toin, ~~cure~~the ~~non-compliance~~trading ~~with~~prices ~~this~~of ~~standard.~~equity ~~For~~securities ~~instance, an issuer~~ generally ~~has~~could ~~six~~affect ~~months to cure~~ the ~~listing~~price ~~standard~~of ~~related~~our to stock. ~~price~~The ~~(including~~stock ~~through~~markets afrequently ~~reverse-stock~~experience ~~split),~~price ~~during~~and ~~which~~volume ~~time~~volatility ~~the~~that ~~issuer's~~affects ~~common~~many companies’ stock ~~would~~prices, ~~continue~~often toin beways ~~traded~~unrelated onto the ~~NYSE,~~operating ~~subject~~performance toof ~~compliance~~those ~~with~~companies. ~~the~~In ~~other~~addition, ~~continued~~the ~~listing~~trading ~~standards.~~price ~~A delisting~~ of our common stock ~~from~~may ~~the~~be ~~NYSE~~increased ~~could~~at ~~negatively~~times ~~impact~~by usmarket ~~because~~phenomena itsuch ~~could~~as ~~reduce~~significant ~~the~~increases ~~liquidity~~in ~~and~~retail ~~market~~investor ~~price~~interest ~~of our common stock~~ and ~~reduce~~purchases ~~the number of investors willing~~ to ~~hold~~cover orshort ~~acquire~~positions. ~~our~~If ~~common stock~~so, ~~which~~those ~~could~~market ~~negatively~~phenomena ~~impact~~could ~~our~~reverse ~~ability~~themselves toat ~~raise~~any ~~equity financing~~time, ~~and/or~~leading ~~diminish~~to ~~the~~a ~~value~~rapid ofand ~~equity~~substantial ~~incentives~~decline ~~available~~in tothe ~~provide~~price toof our ~~employees~~stock.

If we cannot meet the financial compliance standards for continued listing on the New York Stock Exchange (the “NYSE”), the NYSE may delist our common stock, which could have an adverse impact on the trading volume, liquidity and market price of our common stock.

A delisting of our common stock from the NYSE could negatively impact us because it could reduce the liquidity and market price of our common stock and reduce the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing, and/or diminish the value of equity incentives available to provide

Table of Contents

to our employees. The NYSE Listed Company Manual has a set of financial compliance standards we must meet to avoid being delisted from the NYSE. The financial compliance standards are defined below:

•average market capitalization of not less than $50 million over a 30 trading day period and stockholders’ equity of not less than $50 million;

•average closing share price of $1.00 over a 30 trading day period; and

•average market capitalization of not less than $15 million over a 30 day trading period, which is a minimum threshold for continued listing with no cure period.

On March 10, 2020, we were notified by the NYSE that the average closing price of our common stock over the prior 30- consecutive trading day period was below $1.00. On October 30, 2020, we completed a 1-for-50 reverse stock split of our common stock to satisfy this requirement. The reverse stock split reduced the number of shares of our outstanding common stock from 215,255,925 shares as of October 30, 2020 to 4,305,119 shares, subject to adjustment of the rounding of fractional shares.

On November 4, 2020, we were notified by the NYSE that our average market capitalization was less than $50 million over the prior 30-consecutive trading day period along with a stockholders’ equity balance of less than $50 million. As set forth in the notice, as of November 3, 2020, our prior 30-consecutive trading day average market capitalization was $42.5 million and our last reported shareholders’ equity as of June 30, 2020 was $2.2 million. In accordance with NYSE listing requirements, we submitted a plan on December 18, 2020 advising the NYSE of definitive action we have taken, or are taking, to bring us into conformity within 18 months of November 4, 2020. On January 28, 2021, the NYSE accepted our plan allowing our common stock to continue to be listed and traded on the NYSE during the cure period, subject to our compliance with the plan and other continued listing standards. The NYSE will review our compliance with the plan on a quarterly basis. If we fail to comply with the plan or do not meet continued listing standards at the end of the 18-month cure period, we will be subject to the prompt initiation of NYSE suspension and delisting procedures. Further, if our average market capitalization goes below $15 million over a 30-consecutive trading day period, there is no cure period for continued listing on the NYSE.

Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of us, which could adversely affect the price of our common stock.

Delaware corporate law and our current certificate of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:

• giving the board the exclusive right to fill all board vacancies;

• requiring special meetings of stockholders to be called only by the board;

• requiring advance notice for stockholder proposals and director nominations;

• prohibiting stockholder action by written consent;

• prohibiting cumulative voting in the election of directors; and

• allowing for authorized but unissued common and preferred shares.

These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions that are opposed by our board. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, and this may limit the price that investors are willing to pay in the future for shares of our common stock.

Risks Related to our Senior Notes and Amended Credit Facility

We may not be able to generate enough cash flow to meet our debt obligations, including our obligations and commitments under our senior notes and our Amended Credit Facility.

We expect that our earnings and cash flow could vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flow may be insufficient to meet our debt obligations and commitments, including our 7.0% Senior Notes due 2022 ("7.0% Senior Notes"), 8.75% Senior Notes due 2025 ("8.75% Senior Notes") and our Amended Credit Facility. Any insufficiency could negatively impact our business. A range of economic, competitive, business, and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to repay our debt. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control. In particular, these risks have been significantly exacerbated by the sustained decline in commodity prices.

Table of Contents

As of December 31, 2019, the total outstanding principal amount of our indebtedness was $765.0 million, and we had $334.0 million in additional borrowing capacity under our Amended Credit Facility, which, if borrowed, would be secured debt effectively senior to the Senior Notes to the extent of the value of the collateral securing that indebtedness. The borrowing base is dependent on our proved reserves and was, as of December 31, 2019, $500.0 million based on our proved reserves and hedge position. Our borrowing capacity is reduced by a $26.0 million letter of credit. As of December 31, 2019, we had $140.0 million outstanding under our Amended Credit Facility.

The borrowing base is set at the sole discretion of the lenders. Our next scheduled borrowing base redetermination is scheduled on or about April 1, 2020 based on proved reserves as of December 31, 2019 at updated bank price decks and hedge position. However, in the event of lower capital investment in our properties due to a sustained cycle of low commodity prices, we could see lower quantities of proved developed reserves which would, in combination with lower oil and gas commodity pricing, lead to lower borrowing bases.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake one or more alternative financing plans, such as:

• refinancing or restructuring our debt;

• selling assets;

• reducing or delaying capital investments; or

• seeking to raise additional capital.

Our debt could have important consequences. For example, it could:

• increase our costs of doing business;

• increase our vulnerability to general adverse economic and industry conditions;

• limit our ability to fund future capital expenditures and working capital, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt;

• limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

• impair our ability to obtain additional financing in the future; and

• place us at a competitive disadvantage compared to our competitors that have less debt.

We may be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indentures governing the senior notes and our Amended Credit Facility impose on us.

The Amended Credit Facility also contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. We expect to be in compliance with all financial covenants based on our 2020 budget at current commodity prices. However, if commodity prices significantly decline, EBITDAX will be significantly reduced, which is a critical underpinning of our required financial covenants. If this were to occur, it will make it necessary for us to negotiate an amendment to one or more of these financial covenants.

If we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders and holders of our notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such debt or take other actions to pay the accelerated debt. Even if new financing were available at that time, it may not be on terms that are acceptable to us. A breach of any covenant would also limit the funds available under our Amended Credit Facility. In September 2015, we obtained an amendment to the Amended Credit Facility that replaced our debt-to-EBITDAX covenant in the facility for a limited period of time. Through March 31, 2018, the covenants are secured debt-to-EBITDAX and EBITDAX-to-interest. There can be no assurance that we will be able to obtain similar amendments, or waivers of covenant breaches, in the future if needed.

Risks Related to Tax

Table of Contents

We may incur more taxes as a result of new tax legislation.

The Tax Cut and Jobs Act (the "“TCJA"”) was passed in December 2017 and included provisions that could limit certain tax deductions:

• interest expense is limited to 30% of our taxable income (with certain adjustments);

• expanded Section 162(m) limitations on the deductibility of officers'’ compensation; and

• net operating losses ("“NOL"”) incurred after 2017 are limited to 80% of taxable income but can be carried forward indefinitely.

These changes may increase our future tax liability in some circumstances. In addition, proposals are made from time to time to amend U.S. federal and state income tax laws in ways that would be adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling.

~~Our future utilization of NOLs and tax credit carryforwards have been limited by the Merger and may be further limited based on current Internal Revenue Code restrictions.~~34

WeTable have significant deferred tax assets for Federal and state NOL carryforwards. Subject to certain limitations and applicable expiration dates, these tax attributes can be carried forward to reduce our federal income tax liability for future periods. Under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"), the ability to utilize NOL carryforwards to offset future taxable income is subject to limitation if a greater than 50% ownership change occurs ("Section 382 change of ownership"). A Section 382 change of ownership refers to an increase in ownership of more than 50% of our shares by certain groups of shareholders during any three-year period, as determined under certain conventions.Contents

~~The~~U.S. ~~Merger~~federal ~~resulted~~income intax apreferences ~~Section~~currently ~~382~~available ~~change~~with ofrespect ~~ownership,~~to ~~limiting~~crude ~~our~~oil ~~ability~~and tonatural ~~use~~gas ~~pre-change~~exploration ~~NOLs~~ and ~~credits~~production. ~~against~~The ~~post-change~~changes ~~taxable~~could ~~income~~include to(i) anthe ~~annual~~repeal ~~limitation~~of ~~amount~~the ~~plus~~percentage ~~certain~~depletion ~~built-in~~deduction ~~gains~~for ~~recognized~~crude ~~within~~oil ~~five~~and ~~years~~natural ofgas ~~the~~properties, ~~ownership change~~ (~~"RBIG"~~ii). ~~The~~the ~~annual~~elimination ~~limitation amount~~ of ~~$11.7~~current ~~million~~deductions ~~was~~for ~~computed~~intangible bydrilling ~~multiplying~~and ~~our~~development ~~fair~~costs ~~market~~and ~~value~~(iii) onan ~~the~~extension ~~date~~ of the ~~ownership~~amortization ~~change~~period byfor acertain ~~published~~geological ~~long-term tax-exempt bond rate. Our RBIG is projected to be $176.9 million. We have reduced our federal~~ and ~~state~~geophysical ~~NOLs by $276~~expenditures.1 ~~million and $14.0 million~~Also, ~~respectively, and eliminated our~~ state ~~tax~~severance ~~credits~~taxes bymay ~~$8.2~~increase ~~million~~in ~~to reflect~~ the ~~expected~~states ~~impact~~in ofwhich ~~the~~we ~~Section 382 change of ownership~~operate. ~~Deferred~~This ~~tax~~could ~~assets~~adversely ~~and~~affect ~~the~~our ~~corresponding~~existing ~~valuation~~operations ~~allowance~~in ~~have been reduced by $65.0 million for~~ the ~~expected~~relevant ~~tax-effected~~state ~~impact~~and of the ~~Section~~economic ~~382~~viability ~~change~~ of ~~ownership.~~future drilling.

Our future utilization of NOLs and tax credit carryforwards have been limited by the 2018 Merger and may be further limited based on current Internal Revenue Code restrictions.

We have significant deferred tax assets for Federal and state NOL carryforwards. Subject to certain limitations and applicable expiration dates, these tax attributes can be carried forward to reduce our federal income tax liability for future periods. Under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), the ability to utilize NOL carryforwards to offset future taxable income is subject to limitation if a greater than 50% ownership change occurs (“Section 382 change of ownership”). A Section 382 change of ownership refers to an increase in ownership of more than 50% of our shares by certain groups of shareholders during any three-year period, as determined under certain conventions.

The 2018 Merger resulted in a Section 382 change of ownership, limiting our ability to use pre-change NOLs and credits against post-change taxable income to an annual limitation amount plus certain built-in gains recognized within five years of the ownership change (“RBIG”). The annual limitation amount of $11.7 million was computed by multiplying our fair market value on the date of the ownership change by a published long-term tax-exempt bond rate. Our RBIG is projected to be $176.9 million. We have reduced our federal and state NOLs by $274.7 million and $13.1 million, respectively, and eliminated our state tax credits by $8.2 million to reflect the expected impact of the Section 382 change of ownership. Deferred tax assets and the corresponding valuation allowance have been reduced by $65.0 million for the expected tax-effected impact of the Section 382 change of ownership.

Our future utilization of NOLs and tax credit carryforwards may be further limited in the event of any future ownership changes, including the pending Merger with Bonanza Creek.

Item 1B. Unresolved Staff Comments.

~~None~~Not applicable.

Item 3. Legal Proceedings.

We are involved in various legal or governmental proceedings in the ordinary course of business. These proceeding are subject to the uncertainties inherent in any litigation. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management does not believe that the resolution of any currently pending proceeding will have a material adverse effect on our financial condition or results of operations., other than the following.

As ~~previously~~Sterling ~~disclosed,~~Energy inInvestments ~~our~~LLC ~~Annual~~v. ~~Report~~HighPoint onOperating ~~Form10-K~~Corporation, ~~for~~2020CV32034, ~~the~~District ~~year~~Court ~~ended~~in ~~December~~Denver, 31Colorado. On June 15, ~~2018~~2020, weSterling ~~received~~Energy ~~initial~~Investments ~~and~~LLC ~~supplemental~~(“Sterling”) ~~EPA~~filed ~~"Section~~a ~~114"~~complaint ~~mandatory~~against ~~information~~HighPoint ~~directives~~Operating Corporation, asa ~~well~~subsidiary asof ~~parallel~~ours, ~~"compliance~~for ~~advisories"~~breach ~~from~~of ~~the~~contract ~~Colorado~~related ~~Department~~to ofa ~~Public~~Gas ~~Health~~Purchase ~~and~~Agreement ~~Environment~~dated ~~("CDPHE").~~effective ~~These~~November ~~directives~~1, ~~led~~2017, toby ~~settlement~~and ~~negotiations~~between ~~with~~HighPoint ~~EPA~~Operating Corporation and ~~CDPHE~~Sterling. InSterling ~~April~~alleges ~~2019,~~that weHighPoint ~~entered~~Operating ~~into~~Corporation abreached ~~consent~~the ~~decree~~contract ~~with~~by ~~the~~failing ~~EPA~~to ~~and~~use ~~the~~reasonable ~~CDPHE~~commercial efforts to ~~resolve~~deliver ~~these~~to ~~matters~~Sterling at Sterling’s receipt points all quantities of gas not otherwise dedicated to other gas purchase agreements. We vigorously deny Sterling’s claims. Sterling seeks monetary damages in an amount not yet specified. On ~~June~~July 2431, ~~2019~~2020, ~~the~~we ~~Court~~filed ~~approved~~a ~~the~~counterclaim ~~consent~~against ~~decree,~~Sterling ~~which~~for ~~required~~breach of Sterling’s obligations under the ~~Company~~Gas toPurchase ~~pay~~Agreement. ~~$275,000~~We toare ~~the~~seeking ~~United~~monetary ~~States~~damages ~~and~~in ~~$55,000~~an amount not yet specified. The case is scheduled to ~~the~~go ~~State~~to oftrial ~~Colorado,~~in ~~and~~July ~~fund~~2021. aAt ~~supplemental~~this ~~environmental~~time ~~project~~we ~~totaling~~are ~~$220,000,~~unable ~~all~~to ofdetermine ~~which~~whether ~~have~~any ~~been~~loss ~~fulfilled~~is byprobable ~~the~~or ~~Company.~~reasonably ~~Additionally,~~estimate ~~the~~a ~~Company~~range ~~has~~of ~~committed~~such toloss, ~~undertake~~and ~~certain~~accordingly ~~operational~~we ~~enhancements~~have ~~over~~not ~~the~~recognized ~~next~~any ~~three~~liability ~~years~~associated with this matter.

Disclosure of certain environmental matters is required when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that we reasonably believe could exceed $300,000. We have received some Notices of Alleged Violations (“NOAV”) from the Colorado Oil and Gas Conservation Commission (“COGCC”) alleging violations of various Colorado statutes and COGCC regulations governing oil and gas operations. We are engaged in discussions regarding resolution of the alleged violations. We recognized $1.1 million during the year ended December 31, 2020 associated with the NOAVs, as they are probable and reasonably estimable.

Table of Contents

Item 4. Mine Safety Disclosures.

Not applicable.

Table of Contents

PART II

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

Market for Registrant'’s Common Equity

Our common stock is listed on the New York Stock Exchange under the symbol "“HPR"”.

Holders. On February 4, ~~2020~~2021, there were 9177 holders of record of our common stock.

Dividends. We have not paid any cash dividends since our inception. Because we anticipate that all earnings will be retained for the development of our business and our debt agreements limit the payment of cash dividends, we do not expect that any cash dividends will be paid on our common stock for the foreseeable future.

Unregistered Sales of Securities. There were no sales of unregistered equity securities during the year ended December 31, ~~2019~~2020.

Issuer Purchases of Equity Securities. The following table contains information about our acquisitions of equity securities during the three months ended December 31, ~~2019~~2020:

Period	~~TotalNumber ofShares Purchased (1)~~	~~WeightedAverage PricePaid PerShare~~	TotalNumber ofShares Purchased (1)	~~Total Number of SharesPurchased asPart of PubliclyAnnounced Plans orPrograms~~	~~Maximum~~WeightedAverage ~~Number~~PricePaid ~~(orApproximate Dollar Value)of Shares thatMay Yet be PurchasedUnder the Plans orPrograms~~PerShare		Total Number of SharesPurchased asPart of PubliclyAnnounced Plans orPrograms	Maximum Number (orApproximate Dollar Value)of Shares thatMay Yet be PurchasedUnder the Plans orPrograms
October 1 - 31, 2019	1,091	$	1.15	—	—
October 1 - 31, 2020			22		$	10.95	—	—
November 1 - 30, 2019	2,204	$	1.28	—	—
November 1 - 30, 2020			24		$	3.75	—	—
December 1 - 31, 2019	—	$	—	—	—
December 1 - 31, 2020			—		$	—	—	—
Total	~~3,295~~	$	~~1.24~~46	—	—$	7.20	—	—

(1) Represents shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of shares of restricted common stock issued pursuant to our employee incentive plans.

Stockholder Return Performance Presentation

As required by applicable rules of the SEC, the performance graph shown below was prepared based upon the following assumptions:

1. $100 was invested in our common stock on December 31, ~~2014~~2015, and $100 was invested in each of the Standard & Poors SmallCap 600 Index-Energy Sector and the Standard & Poors 500 Index at the closing price on December 31, ~~2014~~2015.

2. Dividends are reinvested on the ex-dividend dates.

Table of Contents

	December 31, 2014		December 31, 2015		December 31, 2016		December 31, 2017		December 31, 2018		December 31, 2019
HPR	$	100	$	35	$	61	$	45	$	22	$	15
S&P SmallCap 600- Energy	100		53		73		54		31		26
S&P 500	100		101		114		138		132		174

Item 6. Selected Financial Data.

The following table presents our selected historical financial data for the years ended December 31, 2019, 2018, 2017, 2016 and 2015. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines, properties acquired or sold and other factors. This information should be read in conjunction with the consolidated financial statements and notes thereto and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" presented elsewhere in this Annual Report on Form 10-K.

Selected Historical Financial Information

The consolidated statement of operations information for the years ended December 31, 2019, 2018 and 2017 and the balance sheet information as of December 31, 2019 and 2018 are derived from our audited consolidated financial statements included elsewhere in this report. The consolidated statement of operations information for the years ended December 31, 2016 and 2015 and the balance sheet information at December 31, 2017, 2016 and 2015 are derived from audited consolidated financial statements that are not included in this report. The information in this table should be read in conjunction with the consolidated financial statements and accompanying notes and other financial data included herein.

Table of Contents

	Year Ended December 31,
	2019			2018			2017			2016			2015
	(in thousands, except per share data)
Statement of Operations Data:
Operating Revenues
Oil, gas and NGL production	$	452,274		$	452,917		$	251,215		$	178,328		$	204,537
Other operating revenues, net	385			100			1,624			491			3,355
Total operating revenues	452,659			453,017			252,839			178,819			207,892
Operating Expenses
Lease operating expense	37,796			27,850			24,223			27,886			42,753
Gathering, transportation and processing expense	10,685			4,644			2,615			2,365			3,482
Production tax expense	23,541			36,762			14,476			10,638			12,197
Exploration expense	143			70			83			83			153
Impairment and abandonment expense	9,642			719			49,553			4,249			575,310
(Gain) loss on sale of properties	2,901			1,046			(92		)	1,078			1,745
Depreciation, depletion and amortization	321,276			228,480			159,964			171,641			205,275
Unused commitments	17,706			18,187			18,231			18,272			19,099
General and administrative expense (1)	44,759			45,130			42,476			42,169			53,890
Merger transaction expense	4,492			7,991			8,749			—			—
Other operating expenses, net	402			1,273			(1,514		)	(316		)	—
Total operating expenses	473,343			372,152			318,764			278,065			913,904
Operating Income (Loss)	(20,684		)	80,865			(65,925		)	(99,246		)	(706,012		)
Other Income and Expense:
Interest and other income	791			1,793			1,359			235			565
Interest expense	(58,100		)	(52,703		)	(57,710		)	(59,373		)	(65,305		)
Commodity derivative gain (loss)	(98,953		)	93,349			(9,112		)	(20,720		)	104,147
Gain (loss) on extinguishment of debt	—			(257		)	(8,239		)	8,726			1,749
Total other income (expense)	(156,262		)	42,182			(73,702		)	(71,132		)	41,156
Income (Loss) before Income Taxes	(176,946		)	123,047			(139,627		)	(170,378		)	(664,856		)
(Provision for) Benefit from Income Taxes	42,116			(1,827		)	1,402			—			177,085
Net Income (Loss)	$	(134,830	)	$	121,220		$	(138,225	)	$	(170,378	)	$	(487,771	)
Income per common share:
Basic	$	(0.64	)	$	0.64		$	(1.80	)	$	(3.08	)	$	(10.10	)
Diluted	$	(0.64	)	$	0.64		$	(1.80	)	$	(3.08	)	$	(10.10	)
Weighted average common shares outstanding, basic	210,392			188,299			76,859			55,384			48,303
Weighted average common shares outstanding, diluted	210,392			189,241			76,859			55,384			48,303

(1) Included in general and administrative expense is long-term cash and equity incentive compensation of $8.6 million, $7.2 million, $8.3 million, $11.9 million and $10.8 million for the years ended December 31, 2019, 2018, 2017, 2016 and 2015, respectively.

Table of Contents

	Year Ended December 31,
	2019			2018			2017			2016			2015
	(in thousands)
Selected Cash Flow and Other Financial Data:
Net income (loss)	$	(134,830	)	$	121,220		$	(138,225	)	$	(170,378	)	$	(487,771	)
Depreciation, depletion, impairment and amortization	325,130			228,480			209,062			171,824			777,713
Other non-cash items	90,055			(126,385		)	45,603			124,552			(83,760		)
Change in assets and liabilities	(1,720		)	8,126			5,550			(4,262		)	(12,504		)
Net cash provided by operating activities	$	278,635		$	231,441		$	121,990		$	121,736		$	193,678
Capital expenditures (1)	$	361,005		$	508,908		$	260,659		$	98,292		$	287,411

(1) Includes exploration and abandonment expense, which are expensed under successful efforts accounting, of $5.9 million, $0.8 million, $0.5 million, $4.1 million and $3.0 million for the years ended December 31, 2019, 2018, 2017, 2016 and 2015, respectively. Also includes furniture, fixtures and equipment costs of $4.6 million, $0.7 million, $1.0 million, $1.1 million and $1.3 million for the years ended December 31, 2019, 2018, 2017, 2016 and 2015, respectively.

	As of December 31,
	2019		2018		2017		2016		2015
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	16,449	$	32,774	$	314,466	$	275,841	$	128,836
Other current assets	69,988		157,007		53,197		42,611		145,481
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment	2,043,447		2,020,873		1,012,610		1,055,049		1,160,898
Other property and equipment, net of depreciation	20,727		8,650		6,270		7,100		9,786
Other assets (1)	5,441		33,156		4,163		4,740		61,519
Total assets	$	2,156,052	$	2,252,460	$	1,390,706	$	1,385,341	$	1,506,520
Current liabilities	$	175,478	$	248,185	$	148,934	$	85,018	$	145,231
Long-term debt, net of debt issuance costs (1)	758,911		617,387		617,744		711,808		794,652
Other long-term liabilities	138,345		174,790		25,474		16,972		17,221
Stockholders' equity	1,083,318		1,212,098		598,554		571,543		549,416
Total liabilities and stockholders' equity	$	2,156,052	$	2,252,460	$	1,390,706	$	1,385,341	$	1,506,520

(1) We adopted ASU 2015-03 and ASU 2015-15 effective January 1, 2016, which required that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction from the carrying amount of that debt liability and as a result, $8.7 million of debt issuance costs related to our long-term debt were reclassified from deferred financing costs and other noncurrent assets to long-term debt in our consolidated balance sheet as of December 31, 2015.

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

Introduction

The following discussion and analysis should be read in conjunction with the "Selected Historical Financial Information" and the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. See the "Cautionary Note Regarding Forward-Looking Statements" at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in "Items 1 and 2. Business and Properties - Business - Operations - Environmental Matters and Regulation;" "Items 1 and 2. Business and Properties - Business - Operations - Other Regulation of the Oil and Gas

Table of Contents

Industry;" and "Item 1A. Risk Factors" above, all of which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.


	December 31, 2015		December 31, 2016		December 31, 2017		December 31, 2018		December 31, 2019		December 31, 2020
HPR	$	100	$	178	$	131	$	63	$	43	$	5
S&P SmallCap 600- Energy	100		138		101		58		49		30
S&P 500	100		112		136		130		171		203

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

Introduction

The following discussion and analysis should be read in conjunction with the “Selected Historical Financial Information” and the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. See the “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in “Items 1 and 2. Business and Properties - Business - Operations - Environmental Matters and Regulation;” “Items 1 and 2. Business and Properties - Business - Operations - Other Regulation of the Oil and Gas Industry;” and “Item 1A. Risk Factors” above, all of which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

Overview

We develop oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.

We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration ~~and development activities meet stakeholders' expectations and regulatory requirements.~~

Future acquisitions or dispositions could have a material impact on our financial condition and results of operations by increasing or decreasing our reserves, production and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our Amended Credit Facility, sales of properties, and/or the issuance of debt, equity or equity-linked securities. Our prior acquisitions and capital expenditures were financed with a combination of cash on hand, funding from the sale of our equity securities, our Amended Credit Facility, other debt financing and cash flows from operations.

As a result of acquisitions and dispositions of properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful. In addition, past results are not necessarily indicative of future results.

The following table summarizes the estimated net proved reserves and related Standardized Measure for the years indicated. The Standardized Measure is not intended to represent the current market value of our estimated oil and natural gas reserves.

	Year Ended December 31,
	2019		2018		2017
Estimated net proved reserves (MMBoe)	127.4		104.6		85.8
Standardized measure (1) (in millions)	$	973.9	$	1,276.0	$	829.3

(1) December 31, 2019 reserves were based on average prices of $55.85 WTI per Bbl of oil, $2.58 Henry Hub per Mcf of natural gas and a percentage of the of the average oil price per Bbl of NGL. December 31, 2018 reserves were based on average prices of $65.56 WTI for oil, $3.10 Henry Hub for natural gas and $32.71 for NGLs. December 31, 2017 reserves were based on average prices of $51.34 WTI for oil, $2.98 Henry Hub for natural gas and $27.40 for NGLs.

Commodity prices are inherently volatile and are influenced by many factors outside of our control. As of February 4, 2020, we have hedged 5,857,500 barrels of oil, or approximately 54% of our expected 2020 production, and 1,912,500 barrels of oil for our 2021 production at price levels that provide some economic certainty to our cash flows. We focus our efforts on increasing oil, natural gas and NGL reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our revenues and overall cost structure to a level that allows for profitable production.

We operate in one industry segment, which is the development and production of crude oil, natural gas and NGLs, and all of our operations are conducted in the Rocky Mountain region of the United States. Consequently, we currently report a single reportable segment.

For the year ended December 31, 2018, as a result of the closing of the Merger on March 19, 2018, Fifth Creek's revenues and expenses are included in the Audited Consolidated Statement of Operations beginning on March 19, 2018.

Table of Contents

~~Results~~and ofdevelopment ~~Operations~~activities meet stakeholders’ expectations and regulatory requirements.

~~Year~~The ~~Ended~~following ~~December 31,~~table ~~2019~~summarizes ~~Compared~~the ~~with~~estimated ~~Year~~net ~~Ended~~proved ~~December 31,~~reserves ~~2018~~ and related Standardized Measure for the years indicated. The Standardized Measure is not intended to represent the current market value of our estimated oil and natural gas reserves.

The following table sets forth selected operating data for the periods indicated:


	Year Ended December 31,
	2020		2019		2018
Estimated net proved reserves (MMBoe)	50.8		127.4		104.6
Standardized measure (1) (in millions)	$	326.8	$	973.9	$	1,276.0

	Year Ended December 31,				Increase (Decrease)
	2019		2018		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production	$	452,274	$	452,917	$	(643	)	—	%
Other operating revenues, net	385		100		285			285	%
Total operating revenues	$	452,659	$	453,017	$	(358	)	—	%
Operating Expenses
Lease operating expense	$	37,796	$	27,850	$	9,946		36	%
Gathering, transportation and processing expense	10,685		4,644		6,041			130	%
Production tax expense	23,541		36,762		(13,221		)	(36	)%
Exploration expense	143		70		73			104	%
Impairment and abandonment expense	9,642		719		8,923			*nm
(Gain) loss on sale of properties	2,901		1,046		1,855			177	%
Depreciation, depletion and amortization	321,276		228,480		92,796			41	%
Unused commitments	17,706		18,187		(481		)	(3	)%
General and administrative expense (1)	44,759		45,130		(371		)	(1	)%
Merger transaction expense	4,492		7,991		(3,499		)	(44	)%
Other operating expenses, net	402		1,273		(871		)	(68	)%
Total operating expenses	$	473,343	$	372,152	$	101,191		27	%
Production Data:
Oil (MBbls)	7,668		6,330		1,338			21	%
Natural gas (MMcf)	16,614		12,864		3,750			29	%
NGLs (MBbls)	2,101		1,697		404			24	%
Combined volumes (MBoe)	12,538		10,171		2,367			23	%
Daily combined volumes (Boe/d)	34,351		27,866		6,485			23	%
Average Realized Prices before Hedging:
Oil (per Bbl)	$	52.86	$	62.04	$	(9.18	)	(15	)%
Natural gas (per Mcf)	1.56		1.75		(0.19		)	(11	)%
NGLs (per Bbl)	10.00		22.18		(12.18		)	(55	)%
Combined (per Boe)	36.07		44.53		(8.46		)	(19	)%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	54.39	$	54.51	$	(0.12	)	—	%
Natural gas (per Mcf)	1.50		1.76		(0.26		)	(15	)%
NGLs (per Bbl)	10.00		22.18		(12.18		)	(55	)%
Combined (per Boe)	36.92		39.85		(2.93		)	(7	)%
Average Costs (per Boe):
Lease operating expense	$	3.01	$	2.74	$	0.27		10	%
Gathering, transportation and processing expense	0.85		0.46		0.39			85	%
Production tax expense	1.88		3.61		(1.73		)	(48	)%
Depreciation, depletion and amortization	25.62		22.46		3.16			14	%
General and administrative expense (1)	3.57		4.44		(0.87		)	(20	)%

(1)December 31, 2020 reserves were based on average prices of $39.54 WTI per Bbl of oil, $1.99 Henry Hub per Mcf of natural gas and a percentage of the of the average oil price per Bbl of NGL. December 31, 2019 reserves were based on average prices of $55.85 WTI for oil, $2.58 Henry Hub for natural gas and a percentage of the of the average oil price per Bbl of NGL. December 31, 2018 reserves were based on average prices of $65.56 WTI for oil, $3.10 Henry Hub for natural gas and $32.71 for NGLs.

*In ~~Not~~early ~~meaningful~~2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus (the “COVID-19 pandemic”). As the virus spread, global economic activity began to slow resulting in a decrease in demand for oil and natural gas. In response, OPEC+ initiated discussions to reduce production to support energy prices. With OPEC+ unable to agree on cuts, energy prices declined sharply during the first half of 2020. While prices partially recovered during the second half of 2020, uncertainties related to the demand for oil and natural gas remain as the COVID-19 pandemic continues to impact the world economy.

The impacts of substantially lower oil, natural gas and NGL prices on our results of operations for the year ended December 31, 2020 were mostly mitigated by hedges in place on 91% of our oil production and 33% of our natural gas production. However, the economics of our existing wells and planned future development were adversely affected, which led to impairments of our proved and unproved oil and gas properties, reductions to our oil and gas reserve quantities and reductions to the borrowing capacity on our Credit Facility.

As of February 4, 2021, we have hedged 3,098,000 barrels and 365,000barrels of our expected 2021 and 2022 oil production, respectively, and 7,590,000 MMbtu and 3,650,000 MMbtu of our expected 2021 and 2022 natural gas production, respectively. However, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. There is uncertainty around the timing of recovery of the global economy from COVID-19 and its effects on the supply and demand for oil, natural gas and NGLs. This uncertainty increases the volatility and amplitude of risks we face as described in “Item 1A. Risk Factors”. If energy prices do not improve, our capital availability, liquidity and profitability will continue to be adversely affected, particularly after our current hedges are realized in 2021.

Table of Contents

~~(1)~~Significant ~~Included~~Business in general and administrative expense is long-term cash and equity incentive compensation of $8.6 million (or $0.69 per Boe) and $7.2 million (or $0.71 per Boe) for the years ended December 31, 2019 and 2018, respectively.Developments

~~Production~~Pending ~~Revenues~~Merger ~~and~~with ~~Volumes.~~Bonanza ~~Production~~Creek ~~revenues decreased to $452.3 million for the year ended December 31~~Energy, ~~2019 from $452~~Inc.9 million for the year ended December 31, 2018. The decrease in production revenues was due to a 19% decrease in the average realized prices per Boe before hedging, offset by a 23% increase in production volumes. The decrease in average realized prices per Boe before hedging decreased production revenues by approximately $86.0 million, while the increase in production volumes increased production revenues by approximately $85.4 million.

~~Total~~On ~~production~~November ~~volumes~~9, 2020, we entered into a Merger Agreement with Bonanza Creek in which HighPoint’s debt will be restructured and HighPoint will merge with a wholly owned subsidiary of 12Bonanza Creek, with HighPoint continuing its existence as the surviving company following the merger and continuing as a wholly owned subsidiary of Bonanza Creek.5 ~~MMBoe~~The ~~for~~Merger is expected to close in the ~~year~~first ~~ended~~quarter ~~December 31,~~of ~~2019~~2021 ~~increased~~under ~~from~~the 10Exchange Offer or in the first or second quarter of 2021 under the Prepackaged Plan.2 ~~MMBoe~~HighPoint ~~for~~paid Bonanza Creek a transaction expense fee of $6.0 million in cash in consideration upon signing the ~~year~~Merger ~~ended~~Agreement ~~December 31,~~with ~~2018~~Bonanza ~~primarily~~Creek. asThe Merger Agreement requires HighPoint to pay Bonanza Creek a ~~result~~termination fee of ~~new~~$15.0 ~~wells~~million, ~~placed~~less ~~into~~the ~~production~~$6.0 ~~throughout~~million ~~2019~~transaction expense fee previously paid, if the agreement is terminated under certain circumstances as defined by the Merger Agreement. See “Items 1 and 2 Business and Properties - Business - Significant Business Developments” for additional information.

Lease Operating Expense ("LOE"). LOE increased to $3.01 per Boe for the year ended December 31, 2019 from $2.74 per Boe for the year ended December 31, 2018. The increase per Boe for the year ended December 31, 2019 compared with the year ended December 31, 2018 is primarily related to higher initial LOE related to our early development program in the Hereford field.

Gathering, Transportation and Processing ("GTP") Expense. GTP expense increased to $0.85 per Boe for the year ended December 31, 2019 from $0.46 per Boe for the year ended December 31, 2018.

Costs incurred to gather, transport and/or process our oil, gas and NGLs prior to the transfer of control to the customer are included in GTP expense. Costs incurred to gather, transport and/or process our oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and thus recorded in oil, gas and NGL production revenues. In general, based on specific contract arrangements, costs incurred associated with gas and NGLs in the Hereford Field are included in GTP expense and costs incurred associated with gas and NGLs in the Northeast Wattenberg Field are included in production revenues. Costs incurred associated with oil are included in production revenues for both areas. See the "Revenue Recognition" section in Note 2 for additional information.

GTP expense for the year ended December 31, 2019 of $0.85 per Boe is primarily associated with the Hereford Field. We expect GTP expense per Boe to increase in the future as we further develop and increase our production from the Hereford Field under the existing contractual arrangement, which has a primary term through April 2027.

Production Tax Expense. Total production taxes decreased to $23.5 million for the year ended December 31, 2019 from $36.8 million for the year ended December 31, 2018. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 5.2% and 8.1% for the years ended December 31, 2019 and 2018, respectively. The decrease in the rate for the year ended December 31, 2019 was due to a decrease in our projected 2019 Colorado severance tax effective rate.

Impairment and Abandonment Expense. Impairment and abandonment expense increased to $9.6 million for the year ended December 31, 2019 from $0.7 million for the year ended December 31, 2018. Impairment and abandonment expense for the year ended December 31, 2019 included leases that have expired and certain leases that will expire subsequent to the balance sheet date that the Company does not plan to renew. Impairment and abandonment expense for the year ended December 31, 2018 included leases that have expired.

We review our oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Whenever we conclude the carrying value may not be recoverable, we estimate the expected undiscounted future net cash flows of our oil and gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, we will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.

Table of Contents

~~Unproved~~Results oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities. Operations

~~Given~~Year ~~current~~Ended ~~and projected future commodity prices~~December 31, we2020 ~~will~~Compared ~~continue~~with toYear ~~review~~Ended ~~our acreage position and future drilling plans. In addition~~December 31, we will assess the carrying value of our properties relative to their estimated future net cash flows. Estimated future net cash flows from our properties are based on our aggregate best estimates of future production, commodity pricing, gathering and transportation deducts, production tax rates, lease operating expenses and future development costs as of the balance sheet date. 2019

~~Depreciation, Depletion and Amortization ("DD&A"). DD&A increased to $321.3 million for the year ended December 31, 2019 compared with $228.5 million for the year ended December 31, 2018.~~ The ~~increase~~following oftable ~~$92.8~~sets ~~million~~forth ~~was~~selected ~~the~~operating ~~result~~data ~~of a 23% increase in production and a 14% increase in the DD&A rate~~ for the ~~year~~periods ended December 31, 2019 compared with the year ended December 31, 2018. The increase in production accounted for a $53.2 million increase in DD&A expense while the increase in the DD&A rate accounted for a $39.6 million increase in DD&A expense.indicated:

Under successful efforts accounting, depletion expense is calculated using the units-of-production method on the basis of some reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the year ended December 31, 2019, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $25.62 per Boe compared with $22.46 per Boe for the year ended December 31, 2018. The increase in the depletion rate of 14% is the result of year end 2018 reserve adjustments.


	Year Ended December 31,				Increase (Decrease)
	2020		2019		Amount		Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues:
Oil, gas and NGL production	$	249,192	$	452,274	$	(203,082)	(45)	%
Other operating revenues, net	1,155		385		770		200	%
Total operating revenues	$	250,347	$	452,659	$	(202,312)	(45)	%
Operating Expenses:
Lease operating expense	$	32,548	$	37,796	$	(5,248)	(14)	%
Gathering, transportation and processing expense	18,467		10,685		7,782		73	%
Production tax expense (1)	(630)		23,541		(24,171)		*nm
Exploration expense	192		143		49		34	%
Impairment and abandonment expense	1,285,085		9,642		1,275,443		*nm
Loss on sale of properties	4,777		2,901		1,876		65	%
Depreciation, depletion and amortization	148,995		321,276		(172,281)		(54)	%
Unused commitments	18,807		17,706		1,101		6	%
General and administrative expense (2)	43,167		44,759		(1,592)		(4)	%
Merger transaction expense	25,891		4,492		21,399		476	%
Other operating expenses (income), net	(544)		402		(946)		*nm
Total operating expenses	$	1,576,755	$	473,343	$	1,103,412	233	%
Production Data:
Oil (MBbls)	5,909		7,668		(1,759)		(23)	%
Natural gas (MMcf)	16,428		16,614		(186)		(1)	%
NGLs (MBbls)	2,352		2,101		251		12	%
Combined volumes (MBoe)	10,999		12,538		(1,539)		(12)	%
Daily combined volumes (Boe/d)	30,052		34,351		(4,299)		(13)	%
Average Realized Prices before Hedging:
Oil (per Bbl)	$	34.62	$	52.86	$	(18.24)	(35)	%
Natural gas (per Mcf)	1.33		1.56		(0.23)		(15)	%
NGLs (per Bbl)	9.69		10.00		(0.31)		(3)	%
Combined (per Boe)	22.66		36.07		(13.41)		(37)	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	53.25	$	54.39	$	(1.14)	(2)	%
Natural gas (per Mcf)	1.30		1.50		(0.20)		(13)	%
NGLs (per Bbl)	9.69		10.00		(0.31)		(3)	%
Combined (per Boe)	32.62		36.92		(4.30)		(12)	%
Average Costs (per Boe):
Lease operating expense	$	2.96	$	3.01	$	(0.05)	(2)	%
Gathering, transportation and processing expense	1.68		0.85		0.83		98	%
Production tax expense (1)	(0.06)		1.88		(1.94)		*nm
Depreciation, depletion and amortization	13.55		25.62		(12.07)		(47)	%
General and administrative expense (2)	3.92		3.57		0.35		10	%

~~Unused~~*Not ~~Commitments~~meaningful. Unused commitments expense of $17.7 million and $18.2 million for the years ended December 31, 2019 and 2018, respectively, related to gas transportation contracts. During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021.

General and Administrative Expense. General and administrative expense decreased to $44.8 million for the year ended December 31, 2019 from $45.1 million for the year ended December 31, 2018. General and administrative expense on a per Boe basis decreased to $3.57 for the year ended December 31, 2019 from $4.44 for the year ended December 31, 2018.

Included in general and administrative expense is long-term cash and equity incentive compensation of $8.6 million and $7.2 million for the years ended December 31, 2019 and 2018, respectively. The components of long-term cash and equity incentive compensation for each of the years ended December 31, 2019 and 2018 are shown in the following table:

	Year Ended December 31,
	2019		2018
	(in thousands)
Nonvested common stock	$	6,601	$	6,036
Nonvested common stock units	1,177		1,138
Nonvested performance cash units (1)	844		52
Total	$	8,622	$	7,226

(1) The nonvested performance cash units are accounted for as liability awards and will be settled in cash for the performance metrics that are met. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date.

Merger Transaction Expense. Merger transaction expense was $4.5 million and $8.0 million for the years ended December 31, 2019 and December 31, 2018, respectively. Transaction expenses included severance, consulting, advisory, legal and other merger-related fees that were not capitalized as part of the Merger.

Table of Contents

~~Interest Expense. Interest expense increased to $58.~~(1)See ~~million~~explanation ~~for~~of ~~the~~negative ~~year~~production ~~ended~~tax ~~December 31,~~expense ~~2019 from $52.7 million~~ for the year ended December ~~31,~~ ~~2018. The increase for the year ended December~~ 31, ~~2019~~2020 ~~was due to borrowings~~ under ~~the~~Production ~~Amended~~Tax ~~Credit~~Expense ~~Facility~~below. ~~See Note 5 for additional information.~~

~~Commodity Derivative Gain~~ (~~Loss~~2).Included ~~Commodity~~in ~~derivative~~general ~~loss~~and ~~was~~administrative ~~$99.0~~expense ~~million~~is ~~for~~long-term ~~the~~cash ~~year~~and ~~ended~~equity ~~December 31,~~incentive ~~2019~~compensation ~~compared with a gain~~ of $~~93.~~3.5 million ~~for~~(or ~~the~~$0.32 ~~year~~per ~~ended~~Boe) ~~December 31,~~and ~~2018~~$8.6 ~~The~~million ~~gain~~ (or ~~loss~~$0.69 onper ~~commodity~~Boe) ~~derivatives~~for isthe ~~related~~years toended ~~fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of~~ December 31, ~~2019~~2020 and ~~2018~~2019, ~~or during the periods then ended~~respectively.

~~The~~Production ~~fair~~Revenues ~~value~~and ofVolumes. ~~our~~Production ~~open~~revenues ~~but~~decreased ~~not~~to ~~yet~~$249.2 ~~settled~~million ~~derivative contracts is based on an income approach using various assumptions, such as quoted forward prices~~ for ~~commodities,~~the ~~risk-free~~year ~~discount~~ended ~~rates~~December 31, ~~volatility~~2020 ~~factors~~from ~~and time value factors~~$452. ~~The~~3 ~~mark-to-market~~million ~~fair~~for ~~value of~~ the ~~open~~year ~~commodity~~ended ~~derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period~~December 31, ~~prior unrealized gains may become unrealized losses and vice versa~~2019. ~~Higher~~The ~~underlying~~decrease ~~commodity~~in ~~price~~production ~~volatility~~revenues ~~will~~was ~~generally~~due ~~lead~~ to ~~higher~~a ~~volatility~~37% decrease in ~~our~~the ~~unrealized~~average ~~gains~~realized ~~and~~prices ~~losses~~per ~~and,~~Boe bybefore ~~association~~hedging, ~~the~~as ~~fair~~well ~~value~~as ofa ~~our~~12% ~~commodity~~decrease ~~derivative contracts. These unrealized gains and losses will impact our net income~~ in ~~the~~production ~~period reported~~volumes. The ~~mark-to-market~~decrease ~~fair~~in ~~value~~average ~~can~~realized ~~create~~prices ~~non-cash~~per ~~volatility~~Boe inbefore ~~our~~hedging ~~reported~~decreased ~~earnings~~production ~~during~~revenues ~~periods~~by ofapproximately ~~commodity price volatility~~$168.2 Wemillion, ~~have~~while ~~experienced such volatility in~~ the ~~past~~decrease ~~and are likely to experience it~~ in ~~the~~production ~~future.~~volumes ~~Gains~~decreased onproduction ~~our derivatives generally indicate lower wellhead~~ revenues inby ~~the~~approximately ~~future~~$34.9 ~~while losses indicate higher future wellhead revenues~~million.

~~The~~Total ~~table~~production ~~below~~volumes ~~summarizes~~of 11.0 MMBoe for the year ended December 31, 2020 decreased from 12.5 MMBoe for the year ended December 31, 2019 as a result of reducing our ~~commodity~~planned ~~derivative~~development ~~gains~~in ~~and~~2020 ~~losses~~as ~~that~~well ~~were~~as ~~recognized~~deferring drilling and completion activity starting in ~~the~~May ~~periods~~2020. ~~presented:~~

	Year Ended December 31,
	2019			2018
	(in thousands)
Realized gain (loss) on derivatives (1)	$	10,667		$	(47,587	)
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)	(81,166		)	20,940
Unrealized gain (loss) on derivatives (1)	(28,454		)	119,996
Total commodity derivative gain (loss)	$	(98,953	)	$	93,349

Lease Operating Expense (“LOE”). LOE decreased to $2.96 per Boe for the year ended December 31, 2020 from $3.01 per Boe for the year ended December 31, 2019. The decrease per Boe for the year ended December 31, 2020 compared with the year ended December 31, 2019 is primarily related to operational efficiencies and a decrease in service industry costs due to a downturn in the industry.

~~(1)~~Gathering, ~~Realized~~Transportation and ~~unrealized~~Processing ~~gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain~~ (~~loss~~“GTP”) ~~in the Consolidated Statements of Operations~~Expense. ~~This~~GTP ~~separate~~expense ~~presentation~~increased isto ~~a non-GAAP measure~~$1.68 ~~Management~~per ~~believes~~Boe ~~the~~for ~~separate presentation of~~ the ~~realized~~year ~~and~~ended ~~unrealized~~December 31, ~~commodity~~2020 ~~derivative~~from ~~gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position~~$0.85 Weper ~~also~~Boe ~~believe that this disclosure allows~~ for athe ~~more~~year ~~accurate~~ended ~~comparison~~December 31, ~~to our peers~~2019.

InCosts ~~2019~~incurred to gather, ~~approximately~~transport ~~88%~~and/or ofprocess our oil, ~~volumes~~gas and ~~19%~~NGLs prior to the transfer of ~~our~~control ~~natural~~to ~~gas~~the ~~volumes~~customer ~~were~~are ~~subject~~included in GTP expense. Costs incurred to ~~financial~~gather, ~~hedges~~transport and/or process our oil, ~~which~~gas ~~resulted~~and inNGLs anafter ~~increase~~control inhas ~~oil~~transferred ~~income~~to the customer are considered components of ~~$11.7~~the ~~million~~consideration received from the customer and athus ~~decrease~~recorded in ~~natural~~oil, gas ~~income~~and ofNGL $1production revenues.0 ~~million~~In ~~after~~general, ~~settlements.~~based Inon ~~2018~~specific contract arrangements, ~~approximately~~costs ~~73%~~incurred ofassociated ~~our~~with ~~oil~~gas ~~volumes~~and NGLs in the Hereford Field are included in GTP expense and ~~14%~~costs ofincurred ~~our~~associated ~~natural~~with gas ~~volumes~~and ~~were~~NGLs ~~covered~~in bythe ~~financial~~Northeast ~~hedges,~~Wattenberg ~~which~~Field ~~resulted~~are primarily included in aproduction ~~decrease~~revenues. inCosts incurred associated with oil are included in production revenues offor ~~$47~~both areas.7 ~~million~~See ~~and~~the an“Revenue ~~increase~~Recognition” ~~natural~~section ~~gas~~in ~~revenues~~Note 2 of ~~$0.1~~the ~~million~~notes ~~after~~to ~~settlements.~~the consolidated financial statements for additional information.

~~Income~~ ~~Tax~~The ~~(Expense)~~increase ~~Benefit.~~in ~~For~~GTP per Boe for the year ended December 31, ~~2019,~~2020 wecompared ~~continue~~ to ~~believe~~2019 ~~that~~was itdue ~~is more likely than not that we will be able~~ to ~~realize~~an aincrease ~~portion~~from ofthe ~~our~~Hereford ~~deferred~~Field ~~tax~~associated ~~assets.~~with ~~This~~an ~~determination~~unfavorable ~~was~~contract ~~made~~assumed ~~by considering all available evidence~~ in ~~assessing~~ the ~~need~~2018 ~~for a valuation allowance~~Merger. ~~Such~~The ~~evidence~~unfavorable ~~includes~~contract ~~the~~amortization ~~scheduled~~reduced ~~reversal~~GTP ofin ~~deferred tax liabilities~~2019, ~~assets~~but ~~acquired~~was infully ~~connection~~amortized ~~with~~by the ~~Merger~~end ~~and~~of ~~their~~2019 ~~classification~~resulting ~~as proved or unproved, current and projected future taxable income and tax planning strategies. In making this assessment, judgment is required~~ in ~~considering~~unfavorable ~~the~~contract ~~relative~~pricing ~~weight~~throughout ~~of negative and positive evidence~~2020.

~~For~~Production Tax Expense. Total production taxes decreased to negative $0.6 million for the year ended December 31, ~~2018,~~2020 wefrom ~~determined~~$23.5 ~~that~~million itfor ~~was~~the ~~more~~year ~~likely~~ended ~~than~~December 31, ~~not~~2019. ~~that~~Production wetaxes ~~would~~are beprimarily ~~able~~based toon ~~realize~~the awellhead ~~portion~~values of ~~our~~production, ~~deferred~~which ~~tax~~exclude ~~assets~~gains and losses associated with hedging activities. ~~This~~Production ~~determination~~tax ~~was~~expense ~~made~~for byboth ~~considering~~periods ~~all~~included ~~available~~an ~~evidence~~annual intrue ~~assessing~~up ~~the~~of ~~need~~Colorado ~~for~~ad avalorem ~~valuation~~and ~~allowance~~severance tax based on actual assessments. ~~Such~~Production ~~evidence~~taxes ~~included~~for the ~~scheduled~~year ~~reversal~~ended December 31, 2020 also included a reduction of ~~deferred~~$5.4 ~~tax~~million ~~liabilities,~~due ~~assets~~to ~~acquired~~a change in ~~connection~~estimate associated with ~~the~~our ~~Merger~~2019 ~~and~~Colorado ~~their~~ad ~~classification~~valorem astax ~~proved~~that oris ~~unproved,~~due ~~current~~in 2021 and ~~projected~~Colorado ~~future~~severance ~~taxable~~tax ~~income~~refunds ~~and~~of $1.8 million based on an audit of tax ~~planning~~years ~~strategies~~2015 to 2017. InExcluding ~~making~~the ~~this~~ad ~~assessment~~valorem adjustments and the severance tax refunds associated with tax years 2015 to 2017, ~~judgment~~production istaxes ~~required~~as ina ~~considering~~percentage of oil, natural gas and NGL sales before hedging adjustments were 6.5% and 6.3% for the ~~relative~~years ~~weight~~ended ofDecember 31, ~~negative~~2020 and ~~positive~~2019, ~~evidence~~respectively.

Impairment and Abandonment Expense. Market conditions led to a decline in the recoverability of the carrying value of our oil and gas properties during the quarter ended March 31, 2020. Since the carrying amount of our oil and gas properties was no longer recoverable, we impaired the carrying value to fair value. Therefore, we recognized non-cash impairment charges of $1.2 billion associated with proved oil and gas properties and $76.3 million associated with unproved oil and gas properties. In addition, as the result of our continuous review of our acreage position and future drilling plans, we recognized non-cash impairment related to our unproved oil and gas properties in the amount of $17.9 million during 2020 associated with certain leases in which the economics may not support renewal or extending at current contracted values. Our impairment and abandonment expense for the year ended December 31, 2020 and 2019 is summarized below:

Table of Contents

As a result of the analysis conducted, we reversed the majority of the valuation allowance on certain deferred tax assets and recorded income tax expense of $1.8 million for the year ended December 31, 2018.


	Year Ended December 31,
	2020		2019
	(in thousands)
Impairment of proved oil and gas properties	$	1,188,566	$	—
Impairment of unproved oil and gas properties	94,209		3,854


Abandonment expense	2,310		5,788
Total impairment and abandonment expense	$	1,285,085	$	9,642

~~Year~~We ~~Ended~~will ~~December 31,~~continue ~~2018~~to ~~Compared~~review ~~with~~our ~~Year~~acreage ~~Ended~~position ~~December 31,~~and ~~2017~~future drilling plans as well as assess the carrying value of our properties relative to their estimated fair values. Lower sustained commodity prices or additional commodity price declines may lead to additional property impairment in future periods.

ADepreciation, ~~discussion~~Depletion ofand ~~our~~Amortization ~~results~~(“DD&A”). ofDD&A ~~operations~~decreased to $149.0 million for the year ended December 31, ~~2018~~2020 compared with $321.3 million for the year ended December 31, ~~2017~~2019. ~~can~~The bedecrease ~~found~~of in$172.3 million was the ~~"Management's~~result ~~Discussion~~of ~~and~~a ~~Analysis~~47% ofdecrease ~~Financial~~in ~~Condition~~the DD&A rate and ~~Results~~a of12% ~~Operations"~~decrease ~~section~~in ofproduction ~~our~~for ~~Annual~~the ~~Report~~year onended ~~Form~~December 31, ~~10-K~~2020 ~~for~~compared with the year ended December 31, ~~2018~~2019. The decrease in the DD&A rate accounted for a $132.9 million decrease in DD&A expense while the decrease in production accounted for a $39.4 million decrease in DD&A expense.

Under successful efforts accounting, depletion expense is calculated using the units-of-production method on the basis of some reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the year ended December 31, 2020, the relationship of historical capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $13.55 per Boe compared with $25.62 per Boe for the year ended December 31, 2019. The decrease in the depletion rate of 47% was a result of recognizing a $1.2 billion impairment associated with our proved oil and gas properties during the quarter ended March 31, 2020.

Unused Commitments. Unused commitments expense of $18.8 million and $17.7 million for the years ended December 31, 2020 and 2019, respectively, primarily related to gas transportation contracts. During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021.

General and Administrative Expense. General and administrative expense decreased to $43.2 million for the year ended December 31, 2020 from $44.8 million for the year ended December 31, 2019. General and administrative expense on a per Boe basis increased to $3.92 for the year ended December 31, 2020 from $3.57 for the year ended December 31, 2019. The decrease in general and administrative expense for the year ended December 31, 2020 was due to a decrease in long-term cash and equity incentive compensation discussed below, partially offset by an increase in legal and advisory fees associated with strategic plans that were contemplated, but not completed. Legal and advisory fees that resulted in the Merger Agreement discussed in Note 1 of the notes to the consolidated financial statements were recognized in merger transaction expense discussed below.

Included in general and administrative expense is long-term cash and equity incentive compensation of $3.5 million and $8.6 million for the years ended December 31, 2020 and 2019, respectively. The decrease for the year ended December 31, 2020 was primarily due to a reduction in overall equity awards granted during the year ended December 31, 2020. In addition, we cancelled all performance cash units during the year ended December 31, 2020. The components of long-term cash and equity incentive compensation for each of the years ended December 31, 2020 and 2019 are shown in the following table:

Table of Contents


	Year Ended December 31,
	2020		2019
	(in thousands)
Nonvested common stock	$	4,106	$	6,601
Nonvested common stock units	543		1,177
Nonvested performance cash units (1)	(1,162)		844
Total	$	3,487	$	8,622

(1)The nonvested performance cash units are accounted for as liability awards. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date. As of December 31, 2020, all nonvested performance cash units were cancelled resulting in a reversal of expense and liability balances.

Merger Transaction Expense. Merger transaction expense was $25.9 million and $4.5 million for the years ended December 31, 2020 and December 31, 2019, respectively. Transaction expenses included consulting, advisory, legal and other merger-related fees associated with the Merger Agreement for the year December 31, 2020 and the 2018 Merger for the year ended December 31, 2019. See Note 4 of the notes to the consolidated financial statements for additional information.

Commodity Derivative Gain (Loss). Commodity derivative gain was $124.9 million for the year ended December 31, 2020 compared with a loss of $99.0 million for the year ended December 31, 2019. The gain or loss on commodity derivatives is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of December 31, 2020 and 2019 or during the periods then ended.

The fair value of our open but not yet settled derivative contracts is based on an income approach using various assumptions, such as quoted forward prices for commodities, risk-free discount rates, volatility factors and time value factors. The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and, by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility due to the COVID-19 pandemic and are likely to experience it in the future. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues.

The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:


	Year Ended December 31,
	2020		2019
	(in thousands)
Realized gain (loss) on derivatives (1)	$	109,583	$	10,667
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)	495		(81,166)
Unrealized gain (loss) on derivatives (1)	14,847		(28,454)
Total commodity derivative gain (loss)	$	124,925	$	(98,953)

(1)Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.

In 2020, approximately 91% of our oil volumes and 33% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $110.1 million and a decrease in natural gas income of $0.5 million after settlements. In 2019, approximately 88% of our oil volumes and 19% of our natural gas volumes were covered by financial hedges, which resulted in an increase in oil income of $11.7 million and a decrease natural gas income of $1.0 million after settlements.

Table of Contents

Income Tax (Expense) Benefit. For the year ended December 31, 2020, as a result of the $1.3 billion impairment, we determined that it was not more likely than not that we would be able to realize existing deferred tax assets. This determination was made by considering all available evidence in assessing the need for a valuation allowance. Such evidence included the scheduled reversal of deferred tax liabilities and current and projected future taxable income and tax planning strategies. In making this assessment, judgment is required in considering the relative weight of negative and positive evidence. As a result of the analysis conducted, we recorded an income tax benefit of $95.9 million. A $1.6 million deferred tax liability has been recorded for projected taxable income in future periods in which only 80% of taxable income can be offset by net operating losses.

For the year ended December 31, 2019, we determined it was more likely than not that we would be able to realize a portion of our deferred tax assets. This determination was made by considering all available evidence in assessing the need for a valuation allowance. Such evidence included the scheduled reversal of deferred tax liabilities, assets acquired in connection with the 2018 Merger and their classification as proved or unproved, current and projected future taxable income and tax planning strategies.

Year Ended December 31, 2019 Compared with Year Ended December 31, 2018

A discussion of our results of operations for the year ended December 31, 2019 compared with December 31, 2018 can be found in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of our Annual Report on Form 10-K for the year ended December 31, 2019.

Capital Resources and Liquidity

~~Our~~Current ~~primary~~Financial ~~sources~~Condition ~~of liquidity since our formation have been net cash provided by operating activities, sales~~ and other issuances of equity and debt securities, bank credit facilities, proceeds from sale-leasebacks, joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources available to us to meet our future financial obligations, fund planned capital expenditure activities and ensure adequate liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources being available to us. We believe that we have sufficient liquidity available to us from cash on hand, cash flows from operations and under our Amended Credit Facility for our planned uses of capital over the next twelve months.Liquidity

~~The~~We ~~Amended~~have financial covenants associated with our Credit Facility ~~provides~~that ~~for~~are ameasured ~~maximum~~each ~~credit~~quarter. ~~amount~~As ofdiscussed ~~$1.5~~in ~~billion,~~the an“Going ~~initial~~Concern” ~~elected~~section ~~commitment~~in ~~amount~~Note 2 of ~~$500.0~~the ~~million,~~notes ~~and~~to anthe ~~initial~~consolidated ~~borrowing~~financial ~~base~~statements, ofbased ~~$500.0~~on ~~million.~~our Onforecasted ~~October~~cash 1,flow ~~2019,~~analysis for the ~~commitment~~twelve ~~and~~month ~~borrowing~~period ~~base~~subsequent ~~amounts~~to ~~were~~the ~~reaffirmed~~date atof ~~$500.0~~this ~~million.~~filing, Atit ~~December 31,~~is ~~2019,~~probable we ~~had~~will ~~cash~~breach ~~and~~a ~~cash~~financial ~~equivalents~~covenant under our Credit Facility in the third quarter of ~~$16~~2021.4 ~~million~~However, ~~and~~timing could change as a ~~$140~~result of changes in our business and the overall economic environment.0 ~~million~~Violation ~~balance~~of ~~outstanding~~any covenant under ~~our~~the ~~Amended~~ Credit Facility. Atprovides ~~December 31,~~the ~~2018,~~lenders wewith ~~had~~the ~~cash~~option ~~and~~to ~~cash~~accelerate ~~equivalents~~the maturity of the Credit Facility, which carries a balance of $32140.80 million ~~and~~as noof ~~amounts~~December ~~outstanding~~31, 2020. This would, in turn, result in cross-default under ~~our~~the ~~Amended~~indentures ~~Credit~~to ~~Facility.~~our ~~Our~~senior ~~effective~~notes, ~~borrowing~~accelerating ~~capacity~~the asmaturity of ~~December 31~~the senior notes, ~~2019~~which ~~was~~have ~~reduced~~a byprincipal balance outstanding of $26625.0 million toas ~~$334~~of December 31, 2020.0 ~~million~~We ~~due~~do tonot anhave ~~outstanding~~sufficient ~~irrevocable~~cash ~~letter~~on ofhand ~~credit~~or ~~related~~available liquidity that can be utilized to arepay ~~firm~~the ~~transportation~~outstanding ~~agreement.~~debt ~~The~~in ~~letter~~the event of ~~credit~~default. ~~will~~These ~~begin~~conditions ~~reducing~~and ~~ratably~~events ~~per~~raise ~~month~~substantial ~~beginning~~doubt ~~April~~about 1,our ~~2020~~ability ~~until~~to itcontinue ~~expires~~as ona ~~August~~going ~~31, 2021~~concern.

OnIn ~~March 19~~addition, ~~2018,~~our weindependent ~~completed~~auditor ~~the~~has ~~Merger~~included ~~with~~an ~~Fifth~~explanatory ~~Creek.~~paragraph ~~The~~regarding ~~Merger~~our ~~was~~ability ~~effected~~to ~~through~~continue ~~the~~as ~~issuance~~a of“going ~~100~~concern” ~~million~~(“going ~~shares~~concern ofopinion”) ~~our~~in ~~common~~its ~~stock,~~report ~~with~~in athis ~~fair~~Annual ~~value~~Report ~~of $484.0 million~~ on ~~the~~Form ~~date of closing~~10-K, ~~and~~which ~~the~~would ~~repayment~~accelerate ofa ~~$53.9~~default ~~million~~under ofour ~~Fifth~~Credit ~~Creek~~Facility ~~debt.~~to ~~See~~the ~~"Items~~filing 1.date ~~and~~of 2.this ~~Business~~Annual ~~and~~Report ~~Properties~~on Form 10-K. ~~Business~~However, -we ~~Significant~~obtained ~~Business~~a ~~Developments~~waiver -from ~~Merger~~our ~~with~~lenders ~~Fifth~~removing ~~Creek~~the ~~Energy~~default ~~Operating~~associated ~~Company,~~with ~~LLC"~~this ~~for~~going ~~additional~~concern ~~information~~opinion.

Sources of Liquidity and Capital Resources

Our primary sources of liquidity since our formation have been net cash provided by operating activities, including commodity hedges, sales and other issuances of equity and debt securities, bank credit facilities and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources available to us to meet our future financial obligations, fund planned capital expenditure activities and ensure adequate liquidity.

We may from time to time seek to retire, purchase or otherwise refinance our outstanding debt securities through cash purchases and/or exchanges, in open market purchases, privately negotiated transactions, exchange offers or otherwise. Any

Table of Contents

such transactions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. On November 9, 2020, we entered into a Merger Agreement with Bonanza Creek pursuant to which HighPoint’s debt will be restructured and HighPoint will merge with a wholly owned subsidiary of Bonanza Creek, with HighPoint continuing its existence as the surviving company following the merger and continuing as a wholly owned subsidiary of Bonanza Creek. The Merger is expected to close in the first quarter under the Exchange Offer or in the first or second quarter of 2021 under the Prepackaged Plan. See “Items 1 and 2 Business and Properties - Business - Significant Business Developments” for additional information.

Our future success in growing proved reserves and production will be highly dependent on capital resources being available to us. Given the levels of market volatility and disruption due to the COVID-19 pandemic and other recent macro and microeconomic factors, the availability of funds from those markets has diminished substantially. Further, arising from concerns about the stability of financial markets generally and the solvency of borrowers specifically, the cost of accessing the credit markets has increased as many lenders have raised interest rates, enacted tighter lending standards, or altogether ceased to provide funding to borrowers.

Cash Flow from Operating Activities

Net cash provided by operating activities was $~~278~~129.60 million, $~~231~~278.46 million and $~~122~~231.04 million in ~~2019~~2020, ~~2018~~2019 and ~~2017~~2018, respectively. The changes in net cash provided by operating activities are discussed above in "“Results of Operations"”. The ~~increase~~decrease in cash provided by operating activities from ~~2017~~2019 to ~~2019~~2020 was primarily due to ana ~~increase~~decrease in production revenues and a decrease in working capital changes due to the timing of cash receipts and disbursements, partially offset by an increase in cash settlements of derivatives.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the prices we receive for the oil, natural gas and NGLs we produce. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors, which include the COVID-19 pandemic, are beyond our control and are difficult to predict.

To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap, swaption and cashless collar contracts to receive fixed prices for a portion of our production. At December 31, ~~2019~~2020, we had in place crude oil swaps covering portions of our ~~2020~~2021 and 2022 production, natural gas swaps covering portions of our 2021 and 2022 production, oil roll swaps covering portions of our 2021 and 2022 production, crude oil swaptions covering portions of our 2022 production and natural gas cashless collars covering portions of our 2021 production. Due to the uncertainty surrounding the COVID-19 pandemic, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future.

In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of oil and natural gas that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, gas and NGL production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value and are included in the Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk. All changes in the derivative’s fair value are recorded in earnings. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the associated derivative instrument contract is settled by making a payment to or receiving a payment from the counterparty.

42The following table includes all hedges entered into through February 4, 2021.

Table of Contents

adjusted for non-performance risk. All changes in the derivative's fair value are recorded in earnings. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the associated derivative instrument contract is settled by making a payment to or receiving a payment from the counterparty.


Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price		Index Price (1)
Swaps
2021
Oil	3,098,000	Bbls	$	54.30					WTI
Natural Gas	5,790,000	MMBtu	$	2.13					NWPL
2022
Oil	365,000	Bbls	$	50.15					WTI
Natural Gas	3,650,000	MMBtu	$	2.13					NWPL
Oil Roll Swaps (2)
2021
Oil	1,554,500	Bbls	$	0.14					WTI
2022
Oil	730,000	Bbls	$	0.22					WTI
Swaptions (3)
2022
Oil	1,092,000	Bbls	$	55.08					WTI
Cashless Collars
2021
Natural Gas	1,800,000	MMBtu			$	2.00	$	4.25	NWPL

~~The~~(1)WTI ~~following~~refers ~~table~~to ~~includes~~West ~~all~~Texas ~~hedges~~Intermediate ~~entered~~price ~~into~~as ~~through~~quoted ~~February 4,~~on ~~2020~~the New York Mercantile Exchange. NWPL refers to the Northwest Pipeline Corporation price as quoted in Platt’s Inside FERC on the first business day of each month.

Contract	TotalHedgedVolumes	QuantityType	WeightedAverageFixed Price		IndexPrice (1)
Swap Contracts:
2020
Oil	5,857,500	Bbls	$	58.32	WTI
2021
Oil	1,912,500	Bbls	$	54.50	WTI

(2)These contracts establish a fixed amount for the differential between the NYMEX WTI calendar month average and the physical crude oil delivery month price. The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.

(13)These ~~WTI~~swaptions ~~refers~~may tobecome ~~West~~effective ~~Texas Intermediate~~ fixed-price asswaps ~~quoted~~at on the ~~New~~counterparty’s ~~York~~election ~~Mercantile~~on ~~Exchange~~December 31, 2021.

By removing the price volatility from a portion of our oil revenue, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for the relevant period. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

It is our policy to enter into derivative contracts with counterparties that are lenders in the ~~Amended~~ Credit Facility, affiliates of lenders in the ~~Amended~~ Credit Facility or potential lenders in the ~~Amended~~ Credit Facility. Our derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. ("“ISDA"”) Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. We are not required to provide any credit support to our counterparties other than cross collateralization with the properties securing the ~~Amended~~ Credit Facility. We have set-off provisions in our derivative contracts with lenders under our ~~Amended~~ Credit Facility which, in the event of a counterparty default, allow us to set-off amounts owed to the defaulting counterparty under the ~~Amended~~ Credit Facility or other obligations against monies owed to us under the derivative contracts. Where the counterparty is not a lender under the ~~Amended~~ Credit Facility, we may not be able to set-off amounts owed by us under the ~~Amended~~ Credit Facility, even if such counterparty is an affiliate of a lender under such facility.

Capital Expenditures

Our capital expenditures are summarized in the following tables for the periods indicated:

	~~Year Ended December 31,~~		Year Ended December 31,
Basin/Area	~~2019~~		2020		~~2018~~		~~2017~~2019		2018
	~~(in millions)~~		(in millions)
DJ	$	~~355.0~~	$	97.3	$	~~508.2~~	$	~~251~~355.50	$	508.2
Other	~~6.0~~		2.2		~~0.7~~		96.20		0.7
Total (1)(2)	$	~~361.0~~	$	99.5	$	~~508.9~~	$	~~260~~361.70	$	508.9

4346

Table of Contents

	~~Year Ended December 31,~~		Year Ended December 31,
	2019				2018		2017
			2020				2019		2018
	~~(in millions)~~		(in millions)
Acquisitions of proved and unproved properties and other real estate	$	~~4.7~~	$	—	$	~~19.9~~	$	~~20.~~4.7	$	19.9
Drilling, development, exploration and exploitation of oil and natural gas properties	~~319.3~~		95.5		~~448.9~~		~~226~~319.93		448.9
Gathering and compression facilities	~~20.4~~		2.8		~~37.1~~		1120.94		37.1
Geologic and geophysical costs	~~12.0~~		0.6		~~2.3~~		012.50		2.3
Furniture, fixtures and equipment	~~4.6~~		0.6		~~0.7~~		14.06		0.7
Total (1)(2)	$	~~361.0~~	$	99.5	$	~~508.9~~	$	~~260~~361.70	$	508.9

(1) Includes exploration and ~~abandonement~~abandonment expense, which are expensed under successful efforts accounting, of $52.95 million, $05.89 million and $0.58 million for the years ended December 31, ~~2019~~2020, ~~2018~~2019 and ~~2017~~2018, respectively.

(2) Excludes $716.2 million related to the proved and unproved oil and gas properties and furniture, equipment and other assets acquired in the 2018 Merger for the year ended December 31, 2018.

Our current estimated capital expenditure budget for the first quarter of 2021 is approximately $3.0 million, primarily associated with flowback on previously completed wells. In addition, in November 2020 we entered into the Merger Agreement with Bonanza Creek, which restricts our near-term capital spending levels and does not allow for drilling or completion operations.

Capital expenditures decreased to $99.5 million for the year ended December 31, 2020 from $361.0 million for the year ended December 31, 2019. The decrease was due to a reduction in planned development for 2020 as well as deferring drilling and completion activity starting in May 2020 due to the COVID-19 pandemic.

Capital expenditures for acquisitions of proved and unproved properties and other real estate were $4.7 million for the year ended December 31, 2019. This was primarily related to acquisitions of proved and unproved properties in the DJ Basin. The decrease in drilling, development, exploration and exploitation of oil and natural gas properties to $319.3 million for the year ended December 31, 2019 from $448.9 million for the year ended December 31, 2018 was primarily related to a decrease in development drilling and completion activities within the DJ Basin. The increase in geologic and geophysical costs to $12.0 million for the year ended December 31, 2019 from $2.3 million for the year ended December 31, 2018 is related to activity in the Hereford field.

Capital expenditures for acquisitions of proved and unproved properties and other real estate were $19.9 million for the year ended December 31, 2018. This was primarily related to acquisitions of proved and unproved properties in the DJ Basin. The increase in drilling, development, exploration and exploitation of oil and natural gas properties to $448.9 million from $226.9 million for the year ended December 31, 2017 primarily related to an increase in development drilling and completion activities within the DJ Basin, including drilling and completion activities associated with properties acquired in the Merger. Capital expenditures for the year ended December 31, 2018 exclude any amounts associated with the purchase price of the Merger.

Our current estimated capital expenditure budget for 2020 is $200.0 million to $220.0 million. The budget includes facilities costs and excludes acquisitions. We may adjust capital expenditures as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If oil, natural gas and NGL prices decline to below acceptable levels or costs increase above acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity. We would generally do this by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow.

We believe that we have sufficient available liquidity with available cash on hand, cash under the Amended Credit Facility and cash flow from operations to fund our 2020 budgeted capital expenditures. Future cash flows are subject to a number of variables, including our level of oil and natural gas production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.

Financing Activities

Merger Financing. On March 19, 2018, we completed the Merger with Fifth Creek. The Merger was effected through the issuance of 100,000,000 shares of our common stock, with a fair value of $484.0 million, and the repayment of $53.9 million of Fifth Creek debt.

Amended Credit Facility. We had $140.0 million and zero outstanding borrowings under the Amended Credit Facility as of December 31, 2019 and 2018, respectively. The Amended Credit Facility provides for a maximum credit amount of $1.5 billion, an initial elected commitment amount of $500.0 million and an initial borrowing base of $500.0 million. On October 1, 2019, the commitment and borrowing base amounts were reaffirmed at $500.0 million. The current maturity date of the Amended Credit Facility is July 16, 2022. While the stated maturity date in the Amended Credit Facility is September 14, 2023,

Table of Contents

the maturity date is accelerated if the Company has more than $100 million of "Permitted Debt" or "Permitted Refinancing Debt" (as those terms are defined in the Amended Credit Facility) that matures prior to December 14, 2023. If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because the Company's 7.0% Senior Notes will mature on October 15, 2022, the aggregate amount of those notes exceeds $100 million and the notes represent "Permitted Debt", the maturity date specified in the Amended Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022.

Borrowing bases are computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by our lenders, as well as any other outstanding debt. Lower commodity prices will generally result in a lower borrowing base.

We are in compliance with all financial covenants as of December 31, 2019 and have complied with all financial covenants since issuance. We expect to be in compliance with all financial covenants based on the 2020 budget at current commodity prices.

Our outstanding debt is summarized below:

		As of December 31, 2019									As of December 31, 2018
				As of December 31, 2020														As of December 31, 2019
	~~Maturity Date~~	~~Principal~~	Maturity Date	~~Debt Issuance Costs~~Principal			~~CarryingAmount~~		Debt Issuance Costs		~~Principal~~		~~Debt Issuance Costs~~CarryingAmount			~~CarryingAmount~~		Principal		Debt Issuance Costs		CarryingAmount
		~~(in thousands)~~		(in thousands)
Amended Credit Facility	~~September 14, 2023~~	$	~~140~~September 14,~~000~~ 2023	$	—140,000		$	~~140,000~~	$	—	$	—	$	—140,000		$	—	$	140,000	$	—	$	140,000
7.0% Senior Notes	~~October 15, 2022~~	~~350,000~~	October 15, 2022	(2350,~~372~~000		)	~~347,628~~		(1,535)		~~350,000~~		(3348,~~210~~465		)	~~346,790~~		350,000		(2,372)		347,628
8.75% Senior Notes	~~June 15, 2025~~	~~275,000~~	June 15, 2025	(3275,~~717~~000		)	~~271,283~~		(3,031)		~~275,000~~		(4271,~~403~~969		)	~~270,597~~		275,000		(3,717)		271,283
Lease Financing Obligation	August 10, 2020	—		—			—				1,859		—			1,859
Total Long-Term Debt (1)				$	765,000				$	(4,566)			$	760,434				$	765,000	$	(6,089)	$	758,911
Total Debt		$	765,000	$	(6,089	)	$	758,911			$	626,859	$	(7,613	)	$	619,246
Less: Current Portion of Long-Term Debt (1)		—		—			—				1,859		—			1,859
Total Long-Term Debt (2)		$	765,000	$	(6,089	)	$	758,911			$	625,000	$	(7,613	)	$	617,387

(1)See AsNote 5 of ~~December 31, 2018,~~ the ~~current~~notes ~~portion~~to ~~of long-term debt included~~ the ~~Lease~~consolidated ~~Financing~~financial ~~Obligation,~~statements ~~which~~for ~~was~~additional ~~settled on February 10, 2019~~information.

Credit Facility. On May 21, 2020, as part of a regular semi-annual redetermination, our Credit Facility was amended. Among other things, the amendment decreased the aggregate elected commitment amount and the borrowing base from $500.0 million to $300.0 million, increased the applicable margins for interest and commitment fee rates and added provisions requiring the availability under the Credit Facility to be at least $50.0 million and the Company’s weekly cash balance (2subject to certain exceptions) ~~See~~to ~~Note~~not 5exceed ~~for~~$35.0 ~~additional~~million. ~~information~~On November 2, 2020, as part of another regular semi-annual redetermination, the Credit Facility was further amended. Among other things, the amendment reduced the Company’s aggregate elected commitment amount to $185.0 million, reduced the borrowing base to $200.0 million and removed the provisions requiring availability under the Credit Facility to be at least $50.0 million. In addition, provisions were amended to

Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody's Investor Services and Standard & Poor's Rating Services currently rate our 7.0% Senior Notes and 8.75% Senior Notes and have assigned a credit rating. We do not have any provisions that are linked to our credit ratings, nor do we have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, the 7.0% Senior Notes or the 8.75% Senior Notes. However, our ability to raise funds and the costs of any financing activities will be affected by our credit rating at the time any such financing activities are conducted.47

Table of Contents

~~Contractual~~prohibit ~~Obligations~~the Company from incurring any additional indebtedness. AThe ~~summary~~Company ofhad ~~our~~$140.0 ~~contractual~~million ~~obligations~~outstanding as of both December 31, 2020 and ~~subsequent~~December to31, 2019. The Company’s available borrowing capacity under the Credit Facility as of December 31, ~~2019~~2020 iswas ~~provided~~$24.0 inmillion, after taking into account $21.0 million of outstanding irrevocable letters of credit, which were issued as credit support for future payments under contractual obligations. Our available borrowing capacity as of the ~~following~~date ~~table:~~of this filing, February 24, 2021, was $34.9 million, after taking into account outstanding irrevocable letters of credit of $18.1 million.

	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	(in thousands)
Notes payable (1)	$	41	$	—	$	—	$	140,000	$	—	$	—	$	140,041
7.0% Senior Notes (2)	24,500		24,500		374,500		—		—		—		423,500
8.75% Senior Notes (3)	24,063		24,063		24,063		24,063		24,063		287,028		407,343
Firm transportation agreements (4)	23,134		19,778		13,064		14,600		14,640		4,800		90,016
Gas gathering and processing agreements (5)(6)	4,569		1,997		—		—		—		—		6,566
Asset retirement obligations (7)	2,218		2,028		2,000		2,020		2,197		15,246		25,709
Derivative liability (8)	4,411		671		—		—		—		—		5,082
Operating leases (9)	2,056		2,355		2,044		2,024		2,078		7,577		18,134
Other (10)	3,448		805		805		745		—		—		5,803
Total	$	88,440	$	76,197	$	416,476	$	183,452	$	42,978	$	314,651	$	1,122,194

While the stated maturity date in the Credit Facility is September 14, 2023, the maturity date is accelerated if we have more than $100.0 million of “Permitted Debt” or “Permitted Refinancing Debt” (as those terms are defined in the Credit Facility) that matures prior to December 14, 2023. If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because our 7.0% Senior Notes will mature on October 15, 2022, the aggregate amount of those notes exceeds $100.0 million and the notes represent “Permitted Debt”, the maturity date specified in the Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022.

~~(1)~~The ~~Included~~borrowing inbase ~~notes~~is ~~payable~~determined isat the ~~outstanding~~discretion ~~principal~~of ~~amount~~the ~~under~~lenders ~~our~~and ~~Amended~~is ~~Credit~~subject ~~Facility~~to ~~due~~regular ~~September~~redetermination 14around April and October of each year, ~~2023.~~as ~~This~~well ~~table~~as ~~does~~following ~~not~~any ~~include~~property ~~future~~sales. ~~commitment~~The ~~fees,~~lenders ~~interest~~can ~~expense~~also orrequest ~~other~~an ~~fees~~interim onredetermination ~~our~~during ~~Amended~~each ~~Credit~~six ~~Facility~~month ~~because~~period. If the ~~Amended~~borrowing ~~Credit~~base ~~Facility~~ is areduced ~~floating~~below ~~rate~~the ~~instrument,~~then-outstanding ~~and~~amount under the Credit Facility, we ~~cannot~~will ~~determine~~be ~~with~~required ~~accuracy~~to repay the ~~timing~~excess of ~~future~~the ~~loan~~outstanding ~~advances,~~amount ~~repayments~~over orthe ~~future~~borrowing ~~interest~~base ~~rates~~over toa beperiod ~~charged.~~of ~~Also~~four ~~included~~months. inThe ~~notes~~borrowing ~~payable~~base is ~~interest~~computed based on aproved ~~$26.0~~oil, ~~million~~natural ~~letter~~gas ofand ~~credit~~NGL reserves that ~~accrues~~have atbeen ~~1.75%~~mortgaged to the lenders, hedge positions and ~~0.125%~~estimated ~~per~~future ~~annum~~cash ~~for~~flows ~~participation~~from ~~fees~~those ~~and~~reserves ~~fronting~~calculated ~~fees,~~using ~~respectively.~~future ~~The~~commodity ~~expected~~pricing ~~term~~provided ~~for~~by the ~~letter~~lenders, ofas ~~credit~~well isas ~~January~~any ~~31,~~other ~~2020~~outstanding debt.

(Going Concern. We have financial covenants associated with our Credit Facility that are measured each quarter. As discussed in the “Going Concern” section in Note 2) ~~The~~of ~~aggregate~~the ~~principal~~notes ~~amount~~to the consolidated financial statements, based on our forecasted cash flow analysis for the twelve month period subsequent to the date of this filing, it is probable we will breach a financial covenant under our 7Credit Facility in the third quarter of 2021.0% ~~Senior~~However, ~~Notes~~timing iscould change as a result of changes in our business and the overall economic environment. Violation of any covenant under the Credit Facility provides the lenders with the option to accelerate the maturity of the Credit Facility, which carries a balance of $~~350~~140.0 million as of December 31, 2020. WeThis ~~are~~would, ~~obligated~~in toturn, ~~make~~result ~~semi~~in cross-~~annual~~default ~~interest~~under ~~payments~~the ~~through~~indentures to our senior notes, accelerating the maturity onof ~~October~~the 15senior notes, ~~2022~~which ~~equal~~have toa principal balance outstanding of $12625.30 million as of December 31, 2020. ~~See~~We ~~Note~~do 5not have sufficient cash on hand or available liquidity that can be utilized to repay the ~~accompanying~~outstanding ~~financial~~debt ~~statements~~in ~~for~~the ~~additional~~event ~~information~~of default. These conditions and events raise substantial doubt about our ability to continue as a going concern.

~~(3)~~In Onaddition, ~~April~~our ~~28,~~independent ~~2017,~~auditor wehas ~~issued~~included ~~$275.0~~an ~~million~~explanatory ~~aggregate~~paragraph ~~principal~~regarding ~~amount~~our ofability ~~8.75%~~to ~~Senior~~continue ~~Notes.~~as Wea ~~are~~“going ~~obligated~~concern” to(“going ~~make~~concern ~~semi-annual~~opinion”) ~~interest~~in ~~payments~~its ~~through~~report ~~maturity~~in this Annual Report on ~~June~~Form 1510-K, ~~2025~~which ~~equal~~would accelerate a default under our Credit Facility to ~~$12.0~~the ~~million~~filing date of this Annual Report on Form 10-K. ~~See~~However, ~~Note~~we 5obtained toa waiver from our lenders removing the ~~accompanying~~default ~~financial~~associated ~~statements~~with ~~for~~this ~~additional~~going ~~information~~concern opinion.

Guarantor Structure. The issuer of our 7.0% Senior Notes and 8.75% Senior Notes is HighPoint Operating Corporation (4f/k/a Bill Barrett), Weor ~~have~~the Subsidiary Issuer. Pursuant to supplemental indentures entered into ~~contracts~~in ~~that~~connection ~~provide~~with ~~firm~~the ~~transportation~~2018 ~~capacity~~Merger, HighPoint Resources Corporation, or the Parent Guarantor, became a guarantor of the 7.0% Senior Notes and the 8.75% Senior Notes in March 2018. In addition, Fifth Pocket Production, LLC, or the Subsidiary Guarantor, became a subsidiary of Subsidiary Issuer on ~~oil~~August 1, 2019 and ~~gas~~also ~~pipeline~~guarantees ~~systems~~the 7.0% Senior Notes and the 8.75% Senior Notes. The ~~contracts~~Parent ~~require~~Guarantor usand tothe ~~pay~~Subsidiary ~~transportation~~Guarantor, ~~demand~~on ~~charges~~a ~~regardless~~joint and several basis, fully and unconditionally guarantee the debt securities of the ~~amount~~Subsidiary weIssuer. ~~deliver~~We tohave no other subsidiaries. All covenants in the ~~processing~~indentures ~~facility~~governing the notes limit the activities of the Subsidiary Issuer and the Subsidiary Guarantor, including limitations on the ability to pay dividends, incur additional indebtedness, make restricted payments, create liens, sell assets or ~~pipeline~~make loans to the Parent Guarantor, but in most cases the covenants in the indentures are not applicable to the Parent Guarantor.

~~(5)~~In ~~Includes~~March 2020, the SEC issued a ~~gas~~final ~~gathering~~rule, Financial Disclosures About Guarantors and ~~processing~~Issuers ~~contract~~of Guaranteed Securities and Affiliates Whose Securities Collateralize a Registrant’s Securities, which ~~requires~~amends usthe disclosure requirements related to ~~deliver~~certain aregistered ~~minimum~~securities ~~volume~~which currently require separate financial statements for subsidiary issuers and guarantors of ~~natural~~registered ~~gas~~debt tosecurities aunless ~~midstream~~certain ~~entity~~exceptions are met. Alternative disclosures are available for ~~gathering~~each subsidiary issuer/guarantor when they are consolidated and ~~processing~~the parent company either issues or guarantees, on a ~~monthly~~full ~~basis.~~and ~~The~~unconditional ~~contract~~basis, ~~requires~~the usguaranteed tosecurities. ~~pay~~If a ~~fee~~registrant ~~associated~~qualifies ~~with~~for alternative disclosure, the ~~contracted~~registrant ~~volumes~~may ~~regardless~~omit summarized financial information when not material and instead provide narrative disclosure of the ~~amount~~guarantor ~~delivered~~structure, including terms and conditions of the guarantees.

(6) Includes reimbursement obligations of $2.4 million. The reimbursement obligations require us to pay a monthly gathering and processing fee per Mcf of production to reimburse midstream entities for costs to construct gas gathering and processing facilities. If the costs are not reimbursed by us via the monthly gathering and processing fees, we must pay the difference.48

(7) Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See "Critical Accounting Policies and Estimates" below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(8) Derivative liability represents the net fair value for oil commodity derivatives presented as liabilities in our Consolidated Balance Sheets as of December 31, 2019. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See "Critical Accounting Policies and Estimates" in Part II, Item 7 and in "Commodity Hedging Activities" above for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

(9) Operating leases primarily includes office leases. Also included are leases of operations equipment which are shown as gross amounts that we are financially committed to pay. However, we will record in our financial statements our proportionate share based on our working interest, which will vary from property to property.

(10) Primarily includes a fresh water commitment contract which requires us to purchase a minimum volume of fresh water from a supplier. The contract requires us to pay a fee associated with the contracted volumes regardless of the amount delivered.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements as of December 31, 2019.

Table of Contents

We qualify for alternative disclosure, and therefore, we are no longer presenting condensed consolidating financial information for the Parent Guarantor, Subsidiary Issuer, or the Subsidiary Guarantor of our debt securities. The assets, liabilities and results of operations of the issuer and guarantors of the guaranteed securities on a combined basis are not materially different than corresponding amounts presented in the consolidated financial statements of the Parent Guarantor as all of the material operating assets and liabilities, and all of our material operations reside within the subsidiary issuer.

Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody’s Investor Services and Standard & Poor’s Rating Services currently rate our 7.0% Senior Notes and 8.75% Senior Notes and have assigned a credit rating. We do not have any credit rating triggers that would accelerate the maturity of amounts due under our Credit Facility, the 7.0% Senior Notes or the 8.75% Senior Notes. However, our ability to raise funds and the costs of any financing activities could be affected by our credit rating at the time any such financing activities are conducted.

Contractual Obligations. A summary of our contractual obligations as of and subsequent to December 31, 2020 is provided in the following table:


	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	(in thousands)
Notes payable (1)(2)	$	306	$	—	$	140,000	$	—	$	—	$	—	$	140,306
7.0% Senior Notes (2)(3)	24,500		374,500		—		—		—		—		399,000
8.75% Senior Notes (2)(4)	24,063		24,063		24,063		24,063		287,031		—		383,283
Firm transportation agreements (5)	19,549		13,064		14,600		14,640		4,800		—		66,653

Asset retirement obligations (6)	2,020		2,000		2,020		2,114		2,406		16,285		26,845
Derivative liability (7)	1,414		2,887		—		—		—		—		4,301
Operating leases (8)	2,691		2,413		2,167		2,078		2,196		5,380		16,925
Other (9)	3,651		11,485		16,345		—		—		—		31,481
Total	$	78,194	$	430,412	$	199,195	$	42,895	$	296,433	$	21,665	$	1,068,794

(1)Included in notes payable is the outstanding principal amount under our Credit Facility due September 14, 2023. This table does not include future commitment fees, interest expense or other fees on our Credit Facility because the Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. While the stated maturity date in the Credit Facility is September 14, 2023, the maturity date is accelerated if we have more than $100.0 million of “Permitted Debt” or “Permitted Refinancing Debt” (as those terms are defined in the Credit Facility) that matures prior to December 14, 2023. If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because our 7.0% Senior Notes will mature on October 15, 2022, the aggregate amount of those notes exceeds $100.0 million and the notes represent “Permitted Debt”, the maturity date specified in the Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022. Also included in notes payable is interest on $21.0 million irrevocable letters of credit, which will continue decrease ratably per month until expiring in August 2021. Interest accrues at 3.25% and 0.125% per annum for participation fees and fronting fees, respectively.

(2)The payment dates could be accelerated. See the “Going Concern” section in Note 2 of the notes to the consolidated financial statements for additional information.

(3)The aggregate principal amount of our 7.0% Senior Notes is $350.0 million. We are obligated to make semi-annual interest payments through maturity on October 15, 2022 equal to $12.3 million. See Note 5 of the notes to the consolidated financial statements for additional information.

(4)The aggregate principal amount of our 8.75% Senior Notes is $275.0 million. We are obligated to make semi-annual interest payments through maturity on June 15, 2025 equal to $12.0 million. See Note 5 of the notes to the consolidated financial statements for additional information.

(5)We have entered into contracts that provide firm transportation capacity on oil and gas pipeline systems. The contracts require us to pay transportation demand charges regardless of the amount we deliver to the pipeline.

(6)Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See “Critical Accounting Policies and Estimates” below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(7)Derivative liability represents the net fair value for oil, gas, and NGL commodity derivatives presented as liabilities in our Consolidated Balance Sheets as of December 31, 2020. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See “Critical Accounting Policies and Estimates”

Table of Contents

below and “Commodity Hedging Activities” above for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

(8)Operating leases primarily includes office leases. Also included are leases of operations equipment which are shown as gross amounts that we are financially committed to pay. However, we will record in our financial statements our proportionate share based on our working interest, which will vary from property to property.

(9)Includes $10.2 million for the year ended December 31, 2022 and $15.3 million for the year ended December 31, 2023 related to a drilling commitment with a joint interest partner which requires us to drill and complete two wells by July 2022 and three wells by 2023. If the drilling commitment is not met, we must return the associated leases that are not held by production to the joint interest partner, which cover approximately 13,000 acres. The Company is also party to minimum volume commitments for the delivery of natural gas volumes to midstream entities for gathering, processing and capital reimbursements as well as minimum volume commitments to purchase fresh water from water suppliers. These commitments require the Company to pay a fee associated with the minimum volumes regardless of the amount delivered.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements as of December 31, 2020.

Trends and Uncertainties

Regulatory Trends. Our future Rockies operations and cost of doing business may be affected by changes in regulations and the ability to obtain drilling permits. The regulatory environment continues to become more restrictive, which limits our ability to conduct, and increases the costs of conducting, our operations. Areas in which we operate are subject to federal, state and local regulations. Additional and more restrictive regulations have been seen at each of these governmental levels recently and there are initiatives underway to implement additional regulations and prohibitions on oil and gas activities. New rules may further impact our ability to obtain drilling permits and other required approvals in a timely manner and increase the costs of such permits or approvals. This may create substantial uncertainty about our production and capital expenditure targets. Efforts related to climate change organized around a “keep it in the ground” message have gained traction in New York and other coastal states, as well as internationally, notably in France and Germany. The movement has found some success in persuading governments, investors and corporations to consider measures to reduce the use of fossil fuels in the future. Examples include local measures to prohibit the use of natural gas for heating, hot water and stoves in new construction; GM’s announcement that it will phase-out gasoline engines in its cars by 2035; and increased pressure on corporations to reduce emissions from the investment community, notably Black Rock and Vanguard. These developments portend a risk that demand for fossil fuels may be significantly reduced in the coming decades. See “Business and Properties-Operations-Environmental Matters and Regulation” for a summary of certain environmental regulations that affect our business and related developments, including potential future regulatory developments.

~~Our future Rockies operations and cost of doing business may be affected by changes in regulations and the ability to obtain drilling permits.~~ The ~~regulatory~~following ~~environment~~trends ~~continues to become more restrictive, which limits our ability to,~~ and ~~increases~~uncertainties ~~the costs of, conducting our operations. Areas in which we operate~~ are subject to federal, state and local regulations. Additional and more restrictive regulations have been seen at each of these governmental levels recently and there are initiatives underway to implement additional regulations and prohibitions on oil and gas activities. New rules may further impact our ability to obtain drilling permits and other required approvals in a timely manner and increase the costs of such permits or approvals. This may create substantial uncertainty about our production and capital expenditure targets. Efforts related to ~~climate change organized around a "keep it in~~ the ~~ground" message have gained traction in New York and other coastal states, as well as internationally, notably in France and Germany. See "Business and Properties~~COVID-~~Operations-Environmental~~19 ~~Matters and Regulation" for a summary of certain environmental regulations that affect our business and related developments, including potential future regulatory developments.~~ pandemic:

Declining Commodity Prices. ~~The~~Energy ~~severe~~prices ~~decline~~declined insharply ~~oil~~during the first half of 2020 due to the COVID-19 pandemic. While prices ~~that~~partially ~~occurred~~recovered induring ~~2014~~the second half of 2020, uncertainties related to the demand for oil and ~~2015~~natural ~~increased~~gas remain as the ~~volatility~~COVID-19 pandemic continues to impact the world economy. The impacts of substantially lower oil, natural gas and ~~amplitude~~NGL prices on our results of operations for the ~~other~~year ~~risks~~ended ~~facing~~December us31, as2020 ~~described~~were mostly mitigated by hedges in ~~this~~place ~~report~~on 91% of our oil production and ~~had~~33% anof ~~impact~~our onnatural gas production. However, the economics of our ~~business~~existing wells and ~~financial~~planned ~~condition. The~~future ~~significant~~development ~~decrease~~were inadversely affected, which led to impairments of our proved and unproved oil ~~prices~~and ingas ~~late~~properties, ~~2018~~reductions to our oil and ~~2019~~gas ~~had~~reserve aquantities ~~similar~~and ~~effect~~reductions to the borrowing capacity on our Credit Facility. IfAs of February 4, 2021, we have hedged 3,098,000 barrels and 365,000 barrels of our expected 2021 and 2022 oil ~~prices~~production, ~~decrease~~respectively, ~~from~~and ~~current~~7,590,000 ~~levels~~MMbtu and 3,650,000 MMbtu of our ~~planned~~expected ~~drilling~~2021 ~~projects~~and ~~may~~2022 ~~become~~natural ~~uneconomic~~gas production, ~~which~~respectively. ~~could~~However, ~~affect~~we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. ~~drilling~~There ~~plans~~is uncertainty around the timing of recovery of the global economy from COVID-19 and ~~growth~~its ~~rates~~effects on the supply and demand for oil, natural gas and NGLs. ~~Low~~This ~~commodity~~uncertainty increases the volatility and amplitude of risks we face as described in “Item 1A. Risk Factors”. If energy prices ~~impact~~do not improve, our ~~revenue~~capital availability, ~~which~~liquidity weand ~~partially~~profitability ~~mitigate~~will ~~with~~continue to be adversely affected, particularly after our ~~hedging~~current ~~program~~hedges are realized in 2021.

~~The~~Employee ~~sustained~~Health ~~decline in commodity prices may also expose us to unexpected liability for plugging~~ and ~~abandoning wells, and associated reclamation, including for assets that were sold to other industry parties in prior years~~Safety. IfThe ~~such~~health ~~third parties become unable to fulfill their contract obligations to us as provided for in purchase~~ and ~~sale~~safety ~~agreements,~~of ~~regulatory~~our ~~agencies~~employees and ~~landowners~~the ~~may~~community ~~demand~~is ~~that~~our wehighest ~~perform such activities~~priority. ~~Recent~~We ~~case~~are ~~law~~also incognizant ~~Wyoming has increased such exposure for companies~~ that ~~have~~supplying ~~divested~~reliable ~~assets~~energy to noour ~~longer~~communities ~~viable entities,~~ and ~~we have received demands from~~ the ~~Bureau~~nation ofis ~~Land~~an ~~Management~~essential ~~and~~function. aThe ~~several~~federal ~~large~~government, ~~ranches~~through tothe ~~plug~~Cybersecurity and ~~abandon~~Infrastructure ~~wells,~~Security ~~and conduct associated reclamation~~Administration, onas ~~properties~~well weas noColorado ~~longer~~state ~~own. We recognized $0.3 million~~ and ~~$1.9~~local ~~million~~“stay-at-home” ~~associated~~orders, ~~with~~have ~~these~~provided ~~obligations~~exemptions ~~in other operating expenses in the Consolidated Statement of Operations~~ for ~~the~~oil ~~years ended December 31, 2019~~ and ~~2018,~~gas ~~respectively~~workers.

Table of Contents

Under our business continuity plan, we were rapidly able to switch to remote operations in response to the COVID-19 pandemic in early March. We successfully transitioned to full remote access and operations, in both the Denver headquarters office and at the field level. The successful transition to remote operations was virtually seamless. From mid-March 2020 through February 2021, based on management’s continuous risk assessments, employees were either fully remote or on a staggered schedule so that approximately 50% of the work force was in the office on a daily basis.

Supply Chain Issues. We have not experienced any recent challenges with respect to obtaining oil field goods and services. However, as oil service and supply companies cut work force and stack rigs and frac fleets, there is the potential for challenges on this front when activity begins to ramp up, although the related timing is highly uncertain.

Critical Accounting Policies and Estimates

The 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 accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 of the ~~Notes~~notes to the ~~Consolidated~~consolidated ~~Financial~~financial ~~Statements~~statements for a discussion of additional accounting policies and estimates made by management.

Oil and Gas Properties

Our oil, natural gas and NGL exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and remain within cash flows from investing activities in the Consolidated Statements of Cash Flows. If an exploratory well does find proved reserves, the costs remain capitalized, are included within additions to oil and gas properties and remain within cash flows from investing activities in the Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether proved reserves are added or not. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well, and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Oil and gas lease acquisition costs are also capitalized. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use.

completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well, and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Oil and gas lease acquisition costs are also capitalized. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. In addition to development on exploratory wells, we may drill scientific wells that are only used for data gathering purposes. The costs associated with these scientific wells are expensed as incurred as exploration expense. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. Maintenance and repairs are charged to expense, and renewals and ~~betterments~~settlements are capitalized to the appropriate property and equipment accounts.

Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters.

We review our oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future net cash flows of our oil and gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, we will impair the carrying value to fair value ~~based on an analysis of quantitative and qualitative factors existing~~ as of the ~~balance~~applicable ~~sheet~~measurement date. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.

Oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, we utilize the income valuation technique, which involves calculating the present value of future net cash flows, as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell. The estimated fair value of assets held for sale may be materially different from sales proceeds that we eventually realize due to a number of factors including but not limited to the differences in expected future commodity pricing, location and quality differentials, our relative desire to dispose of such properties based on facts and circumstances impacting our business at the time we agree to sell, such as our position in the field subsequent to the sale and plans for future acquisitions or development in core areas.

Our investment in producing oil and natural gas properties includes an estimate of the future costs associated with dismantlement, abandonment and restoration of our properties. The present value of the estimated future costs to dismantle, abandon and restore a well location ~~are~~is added to the capitalized costs of our oil and gas properties and recorded as a long-term liability. The capitalized cost is included in the oil and natural gas property costs that are depleted over the life of the assets.

The provision for depletion of oil and gas properties is calculated on a field-by-field basis using the units-of-production method. Natural gas and NGLs are converted to an oil equivalent, Boe, at the standard rate of six Mcf to one Boe and forty-two gallons to one Boe, respectively. Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which incorporate assumptions regarding future development and abandonment costs as well as our level of capital spending. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. This decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.

developed reserves, which incorporate assumptions regarding future development and abandonment costs as well as our level of capital spending. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. This decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.

Oil and Gas Reserve Quantities

Our estimate of proved reserves is based on the quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. Our proved reserves estimates are audited on a well-by-well basis by an independent third party engineering firm. In the aggregate, the independent third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates as of December 31, ~~2019~~2020.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserves estimates. We prepare our reserves estimates, and the projected cash flows derived from these reserves estimates, in accordance with SEC guidelines. Our independent third party engineering firm adheres to the same guidelines when auditing our reserve reports. The accuracy of our reserves estimates is a function of many factors including the following: the quality and quantity of available data, the ~~interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the reserves estimates.~~

interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the reserves estimates.

The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserves estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in our financial statements. As such, reserves estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.

Please refer to the reserve disclosures in "“Items 1 and 2 - Business and Properties"” for further detail on reserves data.

Revenue Recognition

All of our sales of oil, gas and NGLs are made under contracts with customers, whereby revenues are recognized when we satisfy our performance obligations and the customer obtains control of the product. Performance obligations under our contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas and/or NGLs. Accordingly, at the end of the reporting period, we do not have any unsatisfied performance obligations. Our contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of our contracts with customers do not require us to constrain variable consideration for accounting purposes. Our contracts with customers typically require payment within one month of delivery.

Under our contracts with customers, natural gas and its components, including NGLs, are either sold to a midstream entity (which processes the natural gas and subsequently sells the resulting residue gas and NGLs) or are sold to a gas or NGL purchaser after being processed by a third party for a fee. Regardless of the contract structure type, the terms of these contracts compensate us for the value of the residue gas and NGLs at current market prices for each product. Our oil is sold to multiple oil purchasers at specific delivery points at or near the wellhead. All costs incurred to gather, transport and/or process our oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and thus recorded in oil, gas and NGL production revenues in the Consolidated Statements of Operations. All costs incurred prior to the transfer of control to the customer are included in gathering, transportation and processing expense in the Consolidated Statements of Operations.

Gas imbalances from the sale of natural gas are recorded on the basis of gas actually sold by us. If our aggregate sales volumes for a well are greater (or less) than ~~its~~our proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make- up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.

Income Taxes and Uncertain Tax Positions

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes are also recognized for net operating loss carry forwards and tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statement and income tax reporting. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider estimated future taxable income in making such assessments, including the future reversal of taxable temporary differences. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). There can be no assurance that facts and circumstances will not materially change and require us to adjust deferred tax asset valuation allowances in the future.

Accounting guidance for recognizing and measuring uncertain tax positions prescribes a more likely than not recognition threshold that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. Based on this guidance, we regularly analyze tax positions taken or expected to be taken in a tax return based on the threshold prescribed. Tax positions that do not meet or exceed this threshold are considered uncertain tax positions. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. We currently do not have any uncertain tax positions recorded as of December 31, 2019.

We are subject to taxation in many jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions. If we ultimately determine that the payment of these liabilities will be unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine the liability no longer applies. Conversely, we record additional tax charges in a period in which we determine that a recorded tax liability is less than we expect the ultimate assessment to be. See "Results of Operations- Income Tax (Expense) Benefit" above for a discussion of changes to the valuation allowance during 2018.53

prescribed. Tax positions that do not meet or exceed this threshold are considered uncertain tax positions. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. We currently do not have any uncertain tax positions recorded as of December 31, 2020.

We are subject to taxation in many jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions. If we ultimately determine that the payment of these liabilities will be unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine the liability no longer applies. Conversely, we record additional tax charges in a period in which we determine that a recorded tax liability is less than we expect the ultimate assessment to be. See “Results of Operations- Income Tax (Expense) Benefit” above for a discussion of changes to the valuation allowance during 2020.

New Accounting Pronouncements

For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to the Summary of Significant Accounting Policies (in Note 2) of the ~~Notes~~notes to ~~Consolidated~~the consolidated ~~Financial~~financial ~~Statements~~statements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "“market risk"” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our primary market risk exposure is to the prices we receive for our production. Commodity pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for future production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our derivative contracts in place for the year ended December 31, ~~2019~~2020, our income before taxes would have decreased by approximately $10.63 million for each $5.00 per barrel decrease in crude oil prices, $1.31 million for each $0.10 decrease per MMBtu in natural gas prices and $12.92 million for each $1.00 per barrel decrease in NGL prices.

We routinely enter into commodity hedges relating to a portion of our projected production revenue through various financial transactions that hedge future prices received. These transactions may include financial price swaps, ~~whereby~~swaptions or cashless collars. A swap allows us to receive a fixed price for our production and pay a variable market price to the counterparty. A swaption allows the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time or to increase the notional volumes of an existing fixed-price swap. A cashless collar establishes a floor and a ceiling price, which allows us to receive the difference between the floor price and the variable market price if the variable market price is below the floor price. However, we will pay the difference between the ceiling price and the variable market price if the variable market price is above the ceiling. No amounts are paid or received if the variable market price is between the floor and ceiling prices. We have also entered into crude oil swaps to fix the differential in pricing between the NYMEX WTI calendar month average and the physical crude delivery month price (“oil roll swaps”). These commodity hedging activities are intended to support oil, natural gas and NGL prices at targeted levels that provide an acceptable rate of return and to manage our exposure to oil, natural gas and NGL price fluctuations. We do not enter into any market risk sensitive instruments for trading purposes.

50As of February 4, 2021, we have swap and swaption contracts in place to hedge the following volumes for the periods indicated. Further detail of these hedges is summarized in the table presented under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Commodity Hedging Activities”.

Table of Contents

receive a fixed price and pay a variable market price to the contract counterparty. These commodity hedging activities are intended to support oil, natural gas and NGL prices at targeted levels that provide an acceptable rate of return and to manage our exposure to oil, natural gas and NGL price fluctuations. We do not enter into any market risk sensitive instruments for trading purposes.


	For the Year 2021			For the Year 2022
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Swaps
Oil (Bbls)	3,098,000	$	54.30	365,000	$	50.15
Natural Gas (MMbtu)	5,790,000	2.13		3,650,000	2.13
Oil Roll Swaps (1)
Oil (Bbls)	1,554,500	0.14		730,000	0.22
Swaptions (2)
Oil (Bbls)	—	—		1,092,000	55.08

As(1)These ~~of February 4, 2020, we have swap~~ contracts ~~related~~establish toa ~~oil~~fixed ~~volumes~~amount ~~in place~~ for the ~~following~~differential ~~periods~~between ~~indicated.~~the ~~Further~~NYMEX ~~detail~~WTI ofcalendar ~~these~~month ~~hedges~~average isand ~~summarized in~~ the ~~table~~physical ~~presented~~crude ~~under~~oil ~~"Item~~delivery 7month price. ~~Management's~~The ~~Discussion~~weighted ~~and~~average ~~Analysis~~differential represents the amount of ~~Financial~~reduction ~~Condition~~to ~~and~~NYMEX ~~Results~~WTI ofprices ~~Operations—~~for ~~Capital~~the ~~Resources~~notional ~~and~~volumes ~~Liquidity—~~covered ~~Commodity~~by ~~Hedging~~the ~~Activities"~~swap contracts.

	For the Year 2020			For the Year 2021
	DerivativeVolumes	Weighted AveragePrice		DerivativeVolumes	Weighted AveragePrice
Oil (Bbls)	5,857,500	$	58.32	1,912,500	$	54.50

(2)These swaptions may become effective fixed-price swaps at the counterparty’s election on December 31, 2021.

As of February 4, 2021, the Company had cashless collars in place to hedge the following volumes for the periods indicated:


	For the Year 2021
	Derivative Volumes	Weighted Average Floor		Weighted Average Ceiling
Cahless Collars
Natural Gas (MMbtu)	1,800,000	$	2.00	$	4.25

Item 8. Financial Statements and Supplementary Data.

The information required by this item is included below in "“Item 15. Exhibits, Financial Statement Schedules"”.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of December 31, ~~2019~~2020, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Exchange Act. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective as of December 31, ~~2019~~2020.

Management'’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining internal control over financial reporting. Our internal control over financial reporting is a process designed under the supervision of our principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Management has assessed the effectiveness of our internal control over financial reporting. In making this assessment, it used the criteria set forth by the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment we have concluded that, as of December 31, ~~2019~~2020, our internal control over financial reporting is effective.

~~Our~~Changes ~~independent~~in ~~registered~~Internal ~~public~~Controls. ~~accounting~~There ~~firm~~was ~~has~~no ~~issued~~change anin ~~attestation report on~~ our internal control over financial reporting. ~~That~~during ~~report~~the fourth fiscal quarter of 2020 that has materially affected, or is ~~set~~reasonably ~~forth~~likely ~~below~~to materially affect, our internal control over financial reporting.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the fourth fiscal quarter of 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.55

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and Board of Directors of

HighPoint Resources Corporation

Denver, Colorado

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of HighPoint Resources Corporation and subsidiaries (the "Company") as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2019, of the Company and our report dated February 26, 2020, expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Denver, Colorado

February 26, 2020

Item 9B. Other Information.

~~None~~Paul W. Geiger, Chief Operating Officer of the Company, has left the Company effective as of February 23, 2021 (the “Effective Date”). Mr. Geiger’s separation is not the result of any disagreement with the Company. Pursuant to a compensation agreement dated as of October 9, 2020, Mr. Geiger was paid $1,731,490, subject to clawback of the after-tax amount of the payment in the event of certain terminations of employment, including a voluntary resignation. In connection with Mr. Geiger’s separation, Mr. Geiger will be required to repay $79,002 to the Company, and the Board of Directors of the Company has taken action to waive the remaining clawback obligation, subject to his execution and non-revocation of a general release of claims in favor of the Company.

On the Effective Date, R. Scot Woodall, the Company’s Chief Executive Officer and President, will serve as the Company’s principal operating officer. Mr. Woodall, age 59, has served as the Company’s Chief Executive Officer and President since January 2013. Mr. Woodall has served in various positions of increasing responsibility since joining the Company’s predecessor, Bill Barrett Corporation, in 2007. No new compensatory arrangements will be entered into with Mr. Woodall in connection with his appointment as the Company’s principal operating officer.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

The information required by this item will be ~~included~~incorporated inby anreference ~~amendment to this Form 10-K or~~ in ~~the "Directors and Executive Officers" section, the "Section 16(~~a) ~~Beneficial~~future ~~Ownership~~filing ~~Reporting~~with ~~Compliance" section,~~ the ~~"Code~~SEC ~~of Business Conduct and Ethics" section and the "Corporate Governance" section of the proxy statement for the 2020 annual meeting of stockholders, in either case, to be filed~~ within 120 days after December 31, ~~2019, and is incorporated by reference to this report~~2020.

Item 11. Executive Compensation.

The information required by this item will be ~~included~~incorporated inby anreference ~~amendment to this Form 10-K or~~ in ~~the~~a ~~"Executive~~future ~~Compensation"~~filing ~~section~~with ~~and~~ the ~~"Director~~SEC ~~Compensation" section of the proxy statement for the 2020 annual meeting of stockholders, in either case, to be filed~~ within 120 days after December 31, ~~2019, and is incorporated by reference to this report~~2020.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

~~Information~~The ~~regarding~~information ~~beneficial~~required ~~ownership~~by this item will be ~~included~~incorporated inby anreference ~~amendment to this Form 10-K or~~ in ~~the~~a ~~"Beneficial~~future ~~Owners~~filing ofwith ~~Securities" section of~~ the ~~proxy~~SEC ~~statement for the 2020 annual meeting of stockholders, in either case, to be filed~~ within 120 days after December 31, ~~2019, and is incorporated by reference to this report~~2020.

Equity Compensation Plan Information

The following table provides aggregate information presented as of December 31, ~~2019~~2020 with respect to all compensation plans under which equity securities are authorized for issuance.

	~~(a)~~	~~(b)~~	(a)	~~(c)~~	(b)		(c)
Plan Category	~~Number of Securitiesto be Issued UponExercise ofOutstanding Options,Warrants and Rights~~	~~Weighted AveragedExercise Price ofOutstandingOptions, Warrantsand Rights~~	Number of Securitiesto be Issued UponExercise ofOutstanding Options,Warrants and Rights	~~Number of SecuritiesRemaining Availablefor Future Issuance(Excluding SecuritiesReflected in Column (a))~~	Weighted AveragedExercise Price ofOutstandingOptions, Warrantsand Rights		Number of SecuritiesRemaining Availablefor Future Issuance(Excluding SecuritiesReflected in Column (a))
Equity compensation plans approved by shareholders	—	$	—	~~2,296,367~~	$	—	232,311
Equity compensation plans not approved by shareholders	—	—	—	—	—		—
Total	—	$	—	~~2,296,367~~	$	—	232,311

Item 13. Certain Relationships and Related Transactions and Director Independence.

The information required by this item will be ~~included~~incorporated inby anreference ~~amendment to this Form 10-K or~~ in ~~the~~a ~~"Approval~~future offiling ~~Related~~with ~~Party Transactions" section and~~ the ~~"Corporate~~SEC ~~Governance" section of the proxy statement for the 2020 annual meeting of stockholders, in either case, to be filed~~ within 120 days after December 31, ~~2019, and is incorporated by reference to this report~~2020.

Item 14. Principal Accounting Fees and Services.

The information required by this item will be ~~included~~incorporated inby anreference ~~amendment to this Form 10-K or~~ in ~~the~~a ~~"Fees~~future tofiling ~~Independent~~with ~~Auditors" section of~~ the ~~proxy~~SEC ~~statement for the 2020 annual meeting of stockholders, in either case, to be filed~~ within 120 days after December 31, ~~2019, and is incorporated by reference to this report~~2020.

5356

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules.

Report of Independent Registered Public Accounting Firm	59	64
Consolidated Balance Sheets as of December 31, 2019 and 2018	60
Consolidated Balance Sheets as of December 31, 2020 and 2019		67
Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017	61
Consolidated Statements of Operations for the years ended December 31, 2020, 2019 and 2018		68
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017	62
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018		69
Consolidated Statements of Stockholders' Equity for the years ended December 31, 2019, 2018 and 2017	63
Consolidated Statements of Stockholders' Equity (Deficit) for the years ended December 31, 2020, 2019 and 2018		70
Notes to Consolidated Financial Statements	64	71

All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto.

(a)(3) Exhibits.

ExhibitNumber	~~Description of Exhibits~~	Description of Exhibits
2.1	Merger Agreement, dated December 4, 2017, by and among Fifth Creek Energy Operating Company, LLC, Bill Barrett Corporation, Red Rider Holdco, Inc., Rio Merger Sub, LLC, Rider Merger Sub, Inc., Fifth Creek Energy Company, LLC, and NGP Natural Resources XI, L.P. [Incorporated by reference to Exhibit 2.1 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on December 5, 2017.]	Merger Agreement, dated December 4, 2017, by and among Fifth Creek Energy Operating Company, LLC, Bill Barrett Corporation, Red Rider Holdco, Inc., Rio Merger Sub, LLC, Rider Merger Sub, Inc., Fifth Creek Energy Company, LLC, and NGP Natural Resources XI, L.P. [Incorporated by reference to Exhibit 2.1 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on December 5, 2017.]
3.1	Amended and Restated Certificate of Incorporation of HighPoint Resources Corporation. [Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed with the Commission on March 19, 2018.]
2.2		Agreement and Plan of Merger, dated as of November 9, 2020, by and among Bonanza Creek Energy, Inc., Boron Merger Sub, Inc. and HighPoint Resources Corporation. [Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed with the Commission on November 9, 2020.]
3.2	HighPoint Resources Corporation Amended and Restated Bylaws. [Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed with the Commission on March 19, 2018.]
3.1		Amended and Restated Certificate of Incorporation of HighPoint Resources Corporation. [Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed with the Commission on March 19, 2018.]
4.1.1*	Description of Capital Stock.
3.1.1		Certificate of Amendment to the Amended and Restated Certificate of Incorporation of HighPoint Resources Corporation, as filed on October 29, 2020 with the State of Delaware. [Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed with the Commission on October 30, 2020.]
4.1.2	Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of our Quarterly Report on Form 10-Q filed with the Commission on May 8, 2018.]
3.2		HighPoint Resources Corporation Amended and Restated Bylaws. [Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed with the Commission on March 19, 2018.]
4.2	Base Indenture, dated July 8, 2009, between Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on July 8, 2009.]
4.1.1		Description of Capital Stock. [Incorporated by reference to Exhibit 4.1.1 to our Annual Report on Form 10-K filed with the Commission on February 26, 2020.]
4.2.1	Fourth Supplemental Indenture for 7% Senior Notes due 2022, dated March 12, 2012, among Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.2 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on March 12, 2012.]
4.1.2		Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of our Quarterly Report on Form 10-Q filed with the Commission on May 8, 2018.]
4.2.2	Supplemental Indenture to Fourth Supplemental Indenture for 7% Senior Notes due 2022, dated December 13, 2017, among Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on December 15, 2017.]
4.2		Base Indenture, dated July 8, 2009, between Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on July 8, 2009.]
4.2.3	Second Supplemental Indenture to Fourth Supplemental Indenture for 7% Senior Notes due 2022, dated March 19, 2018, among Bill Barrett Corporation, the Company, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on March 19, 2018.]
4.2.1		Fourth Supplemental Indenture for 7% Senior Notes due 2022, dated March 12, 2012, among Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.2 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on March 12, 2012.]

5457

ExhibitNumber	~~Description of Exhibits~~	Description of Exhibits
4.3	Indenture for 8.75% Senior Notes due 2025, dated April 28, 2017, among Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on April 28, 2017.]
4.2.2		Supplemental Indenture to Fourth Supplemental Indenture for 7% Senior Notes due 2022, dated December 13, 2017, among Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on December 15, 2017.]
4.3.1	First Supplemental Indenture for 8.75% Senior Notes due 2025, dated December 13, 2017, by and among Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company. [Incorporated by reference to Exhibit 4.2 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on December 15, 2017.]
4.2.3		Second Supplemental Indenture to Fourth Supplemental Indenture for 7% Senior Notes due 2022, dated March 19, 2018, among Bill Barrett Corporation, the Company, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on March 19, 2018.]
4.3.2	Second Supplemental Indenture for 8.75% Senior Notes due 2025, dated March 19, 2018, among Bill Barrett Corporation, the Company, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on March 19, 2018.]
4.3		Indenture for 8.75% Senior Notes due 2025, dated April 28, 2017, among Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on April 28, 2017.]
10.1	Fourth Amended and Restated Credit Agreement, dated as of September 14, 2018, among HighPoint Resources Corporation as guarantor and its wholly owned subsidiary and the banks named therein. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on September 17, 2018.]
4.3.1		First Supplemental Indenture for 8.75% Senior Notes due 2025, dated December 13, 2017, by and among Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company. [Incorporated by reference to Exhibit 4.2 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on December 15, 2017.]
10.2+	Form of Indemnification Agreement, between HighPoint Resources Corporation and each of the directors and certain executive officers of the Company. [Incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q filed with the Commission on May 8, 2018.]
4.3.2		Second Supplemental Indenture for 8.75% Senior Notes due 2025, dated March 19, 2018, among Bill Barrett Corporation, the Company, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on March 19, 2018.]
10.3(a)+	2012 Equity Incentive Plan. [Incorporated by reference to Appendix A to Bill Barrett Corporation's Definitive Proxy Statement filed with the Commission on April 6, 2017.]
10.1		Fourth Amended and Restated Credit Agreement, dated as of September 14, 2018, among HighPoint Resources Corporation as guarantor and its wholly owned subsidiary and the banks named therein. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on September 17, 2018.]
10.3(b)+	Amendment to the 2012 Equity Incentive Plan. [Incorporated by reference to Exhibit 10.5(b) of our Annual Report on Form 10-K filed with the Commission on February 26, 2019.]
10.1.1		First Amendment to Fourth Amended and Restated Credit Agreement, dated as of May 21, 2020, among HighPoint Resources Corporation, as guarantor, HighPoint Operating Corporation, as borrower, borrower’s subsidiary, and the banks named therein. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on May 26, 2020.]
10.4+	Form of Restricted Common Stock Unit Award for 2012 Equity Incentive Plan. [Incorporated by reference to Exhibit 10.2 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on July 2, 2012.]
10.1.2		Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of November 2, 2020, among HighPoint Resources Corporation, as guarantor, HighPoint Operating Corporation, as borrower, borrower's subsidiary, and the lenders named therein. [Incorporated by reference to Exhibit 10.1 to our Currrent Report on Form 8-K filed with the Commission on November 6, 2020.]
10.5+	Cash Incentive Plan. [Incorporated by reference to Appendix A to Bill Barrett Corporation's Definitive Proxy Statement for the 2016 Annual Meeting of Stockholders filed with the Commission on April 7, 2016.]
10.1.3		Consent and Agreement, dated as of February 1, 2021, by and among HighPoint Operating Corporation, HighPoint Resources Corporation, the Guarantors party thereto, the Lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on February 5, 2021.]
10.6+	Form of Change in Control Severance Protection Agreement. [Incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q filed with the Commission on May 8, 2018.]
10.2+		Form of Indemnification Agreement, between HighPoint Resources Corporation and each of the directors and certain executive officers of the Company. [Incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q filed with the Commission on May 8, 2018.]
10.7*	Form of Stockholders Agreement between Red Rider Holdco, Inc., Fifth Creek Energy Company, LLC, and NGP Natural Resources XI, L.P.
10.3+		2012 Equity Incentive Plan. [Incorporated by reference to Appendix A to Bill Barrett Corporation's Definitive Proxy Statement filed with the Commission on April 6, 2017.]
10.8	Waiver to Stockholders Agreement, dated as of December 4, 2018, by and among HighPoint Resources Corporation, Fifth Creek Energy Company, LLC and NGP Natural Resources XI, L.P. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on December 6, 2018.]
10.3.1+		Amendment to the 2012 Equity Incentive Plan. [Incorporated by reference to Exhibit 10.5(b) of our Annual Report on Form 10-K filed with the Commission on February 26, 2019.]
10.8+	Deferred Compensation Plan. [Incorporated by reference to Exhibit 10.1 to Bill Barrett Corporation's Quarterly Report on Form 10-Q filed with the Commission on May 5, 2016.]
21.1*	Subsidiaries of the Registrant.

5558

ExhibitNumber	~~Description of Exhibits~~	Description of Exhibits
23.1*	Consent of Deloitte & Touche LLP.
10.3.2+		Second Amendment to the 2012 Equity Incentive Plan. [Incorporated by reference to Appendix A of our Proxy Statement on Schedule 14A filed with the Commission on March 18, 2020.]
23.2*	Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers.
10.4+		Form of Restricted Common Stock Unit Award for 2012 Equity Incentive Plan. [Incorporated by reference to Exhibit 10.2 to Bill Barrett Corporation's Current Report on Form 8-K filed with the Commission on July 2, 2012.]
31.1*	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
10.5+		Form of Director’s Restricted Common Stock Unit Award Agreement. [Incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q filed with the Commission on November 9, 2020.]
31.2*	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
10.6+		Form of Performance Unit Grant Agreement. [Incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q filed with the Commission on November 9, 2020.]
32**	Section 1350 Certification of Chief Executive Officer and Chief Financial Officer.
10.7+		Form of Restricted Common Stock Award Agreement. [Incorporated by reference to Exhibit 10.3 of our Quarterly Report on Form 10-Q filed with the Commission on November 9, 2020.]
99.1*	Report of Netherland, Sewell & Associates, Inc. dated January 21, 2020, concerning audit of oil and gas reserve estimates.
10.8+		Cash Incentive Plan. [Incorporated by reference to Appendix A to Bill Barrett Corporation's Definitive Proxy Statement for the 2016 Annual Meeting of Stockholders filed with the Commission on April 7, 2016.]
101.INS	XBRL Instance Document (The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.)
10.9+		Form of Change in Control Severance Protection Agreement. [Incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q filed with the Commission on May 8, 2018.]
101.SCH	XBRL Taxonomy Extension Schema Document
10.10		Form of Stockholders Agreement between Red Rider Holdco, Inc., Fifth Creek Energy Company, LLC, and NGP Natural Resources XI, L.P. [Incorporated by reference to Exhibit 10.7 to our Annual Report on Form 10-K filed with the Commission on February 26, 2020.]
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
10.10.1		Waiver to Stockholders Agreement, dated as of December 4, 2018, by and among HighPoint Resources Corporation, Fifth Creek Energy Company, LLC and NGP Natural Resources XI, L.P. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on December 6, 2018.]
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
10.10.2		Amendment No. 1 to Stockholders Agreement. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on February 26, 2020.]
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
10.11+		Deferred Compensation Plan. [Incorporated by reference to Exhibit 10.1 to Bill Barrett Corporation's Quarterly Report on Form 10-Q filed with the Commission on May 5, 2016.]
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
10.12+*		Form of Compensation Agreement, Retention and Sale Payment.
104	Cover Page Interactive Data File (embedded within the Inline XBRL document).
10.13		Voting and Support Agreement, dated as of November 9, 2020, by and among Bonanza Creek Energy, Inc., Boron Merger Sub, Inc., HighPoint Resources Corporation and Fifth Creek Energy Company, LLC. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on November 9, 2020.]
10.14		Transaction Support Agreement, dated as of November 9, 2020, by and among HighPoint Resources Corporation, HighPoint Resources Corporation, HighPoint Operating Corporation, Fifth Pocket Production, LLC, HPR Consenting 7% Noteholders, HPR Consenting 8.75% Noteholders, and HPR Consenting Shareholders (as such terms are defined therein). [Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed with the Commission on November 9, 2020.]
21*		Subsidiaries of the Registrant.
22*		Subsidiary Guarantors and Issuers of Guaranteed Securities.


Exhibit Number						Description of Exhibits

23.1*						Consent of Deloitte & Touche LLP.

23.2*						Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers.

31.1*						Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

31.2*						Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

32**						Section 1350 Certification of Chief Executive Officer and Chief Financial Officer.

99.1*						Report of Netherland, Sewell & Associates, Inc. dated January 20, 2021, concerning audit of oil and gas reserve estimates.

101.INS						XBRL Instance Document (The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.)

101.SCH						XBRL Taxonomy Extension Schema Document

101.CAL						XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF						XBRL Taxonomy Extension Definition Linkbase Document

101.LAB						XBRL Taxonomy Extension Label Linkbase Document

101.PRE						XBRL Taxonomy Extension Presentation Linkbase Document

104						Cover Page Interactive Data File (embedded within the Inline XBRL document).


+			Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)(3).
*			Filed herewith.
**			Furnished herewith.

5660

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

~~HIGHPOINT RESOURCES CORPORATION~~

HIGHPOINT RESOURCES CORPORATION

Date:

~~February 26, 2020~~

~~By:~~February 24, 2021

~~/s/ R. Scot Woodall~~

By:

/s/ R. Scot Woodall

~~R. Scot Woodall~~

R. Scot Woodall

~~Chief Executive Officer and President~~

Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

~~Title~~

~~Date~~

Title

Date

/s/ R. Scot Woodall

~~Chief Executive Officer, Presidentand Director(Principal Executive Officer)~~

~~February 26, 2020~~

Chief Executive Officer, Presidentand Director(Principal Executive Officer)

February 24, 2021

R. Scot Woodall

/s/ William M. Crawford

~~Chief Financial Officer(Principal Financial Officer)~~

~~February 26, 2020~~

Chief Financial Officer(Principal Financial Officer)(Principal Accounting Officer)

February 24, 2021

William M. Crawford

/s/ David R. Macosko

Senior Vice President— Accounting(Principal Accounting Officer)

February 26, 2020

/s/ Jim W. Mogg

Director

February 24, 2021

David R. Macosko

Jim W. Mogg

/s/ Jim W. Mogg

Director

February 26, 2020

/s/ Scott A. Gieselman

Director

February 24, 2021

Jim W. Mogg

Scott A. Gieselman

/s/ Mark S. Berg

Director

February 26, 2020

/s/ Craig S. Glick

Director

February 24, 2021

Mark S. Berg

Craig S. Glick

/s/ Scott A. Gieselman

Director

February 26, 2020

/s/ Andrew C. Kidd

Director

February 24, 2021

Scott A. Gieselman

Andrew C. Kidd

/s/ Craig S. Glick

Director

February 26, 2020

/s/ Lori A. Lancaster

Director

February 24, 2021

Craig S. Glick

Lori A. Lancaster

/s/ Andrew C. Kidd

Director

February 26, 2020

/s/ Edmund P. Segner, III

Director

February 24, 2021

Andrew C. Kidd

Edmund P. Segner, III

/s/ Lori A. Lancaster

Director

February 26, 2020

/s/ Randy I. Stein

Director

February 24, 2021

Lori A. Lancaster

Randy I. Stein

/s/ William F. Owens

Director

February 26, 2020

William F. Owens

/s/ Edmund P. Segner, III

Director

February 26, 2020

Edmund P. Segner, III

/s/ Michael R. Starzer

Director

February 26, 2020

Michael R. Starzer

/s/ Randy I. Stein

Director

February 26, 2020

Randy I. Stein

/s/ Michael E. Wiley

Director

February 26, 2020

Michael E. Wiley

5761

Table of Contents

FINANCIAL STATEMENTS

INDEX TO FINANCIAL STATEMENTS

HighPoint Resources Corporation
Report of Independent Registered Public Accounting Firm	59	64
Consolidated Balance Sheets as of December 31, 2019 and 2018	60
Consolidated Balance Sheets as of December 31, 2020 and 2019		67
Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017	61
Consolidated Statements of Operations for the years ended December 31, 2020, 2019 and 2018		68
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017	62
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018		69
Consolidated Statements of Stockholders' Equity for the years ended December 31, 2019, 2018 and 2017	63
Consolidated Statements of Stockholders' Equity (Deficit) for the years ended December 31, 2020, 2019 and 2018		70
Notes to Consolidated Financial Statements	64	71

5862

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and Board of Directors of

HighPoint Resources Corporation

Denver, Colorado

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of HighPoint Resources Corporation and subsidiaries (the “Company”) (formerly Bill Barrett Corporation) as of December 31, ~~2019~~2020 and ~~2018~~2019, the related consolidated statements of operations, ~~comprehensive~~stockholders’ ~~income~~equity (~~loss~~deficit), ~~stockholders' equity,~~ and cash flows for each of the three years in the period ended December 31, ~~2019~~2020, 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~~2020 and ~~2018~~2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2019~~2020, in conformity with accounting principles generally accepted in the United States of America.

WeGoing have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2019, based on the criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2020, expressed an unqualified opinion on the Company's internal control over financial reporting.Concern

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company projects it will not maintain compliance with a financial covenant requirement of its Revolving Credit Facility during the next twelve months, which would lead to an acceleration of the maturity of the Company’s debt obligations. The Company does not have sufficient cash on hand or available liquidity that can be utilized to repay such debt obligations, which raises substantial doubt about the Company’s ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These financial statements are the responsibility of the Company'’s management. Our responsibility is to express an opinion on the Company'’s financial statements based on our audits. We are a public accounting firm registered with the 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. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. ~~Our~~The ~~audits~~Company ~~included~~is ~~performing~~not ~~procedures~~required to ~~assess~~have, ~~the~~nor ~~risks~~were ofwe ~~material~~engaged ~~misstatement of the financial statements, whether due~~ to ~~error or fraud~~perform, ~~and~~an ~~performing~~audit ~~procedures~~of ~~that~~its ~~respond~~internal tocontrol ~~those~~over ~~risks~~financial reporting. ~~Such~~As ~~procedures~~part ~~included~~of ~~examining~~our audits, onwe aare ~~test~~required ~~basis,~~to ~~evidence~~obtain ~~regarding~~an ~~the~~understanding ~~amounts~~of ~~and~~internal ~~disclosures~~control inover ~~the~~ financial ~~statements.~~reporting ~~Our~~but ~~audits~~not ~~also~~for ~~included evaluating~~ the ~~accounting~~purpose ~~principles~~of ~~used~~expressing ~~and~~an ~~significant~~opinion ~~estimates~~on ~~made~~the byeffectiveness ~~management,~~of ~~as well as evaluating~~ the ~~overall~~Company’s ~~presentation~~internal ofcontrol ~~the~~over financial ~~statements~~reporting. WeAccordingly, ~~believe~~we ~~that~~express ~~our~~no ~~audits~~such ~~provide a reasonable basis for our~~ 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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Table of Contents

Proved oil and gas properties — Oil and Gas Reserves - Refer to Note 2 to the financial statements

Critical Audit Matter Description

The Company’s proved oil and gas properties are depleted on a field-by-field basis using the units of production method and evaluated for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred, by comparing the carrying amount of the proved oil and gas properties to the undiscounted future net cash flows, derived in part from the underlying oil and gas reserves. The development of the Company’s proved oil and gas reserve quantities and the related future net cash flows used to evaluate proved oil and gas properties for impairment requires management to make significant estimates and assumptions related to calculating the best estimate of future production. The Company engages an independent reserve engineer to audit the estimates, assumptions and engineering data used to develop the best estimate of future production. Changes in these estimates, assumptions or engineering data could have a significant impact on the depletion calculations and proved property impairment evaluations. The proved oil and gas properties balance was $0.5 billion as of December 31, 2020, net of accumulated depletion and impairment. Impairment expense and depletion expense for proved oil and gas properties were $1.2 billion and $0.1 billion, respectively, for the year then ended.

Given the significant judgments made by management, performing audit procedures to evaluate the Company’s proved reserves and the related expected undiscounted future net cash flows, including management’s estimates and assumptions related to the best estimate of future production, required a high degree of auditor judgment and an increased extent of effort.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s significant judgments and assumptions related to oil and gas reserve quantities and estimates of the future net cash flows, included the following, among others:

•We tested the operating effectiveness of controls related to the Company’s estimation of proved reserves and the related expected undiscounted future net cash flows.

•We evaluated the Company’s best estimate of future production by:

◦Comparing the Company’s best estimate of future production to historical production volumes

◦Comparing the Company’s best estimate of future production to those independently developed by the independent reserve engineer

◦Assessing the reasonableness of the production volume decline curves by comparing to historical decline curve estimates

•We evaluated the experience, qualifications and objectivity of management’s expert, an independent reserve engineering firm.

Proved oil and natural gas properties – Impairment and Abandonment Expense - Refer to Note 2 to the financial statements

Critical Audit Matter Description

The Company compares the estimated undiscounted future net cash flows of its oil and gas properties to the carrying amount of the proved oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount of the proved oil and gas properties exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value. The fair value is estimated by using either a market approach based on recent sales prices of comparable properties and/or indications from marketing activities or by using the income valuation technique, which involves calculating the present value of future net cash flows.

During the three months ended March 31, 2020, the Company's proved oil and gas properties with a carrying value of $1.7 billion were reduced to a fair value of $0.5 billion, resulting in an impairment of $1.2 billion which was included in impairment and abandonment expense within the consolidated statement of operations. Management estimated the fair value of the proved developed producing reserves using the income valuation technique. The income valuation technique involves the application of a discount rate commensurate with the risk and current market conditions associated with realizing the projected cash flows.

Table of Contents

Given the Company’s use of an income valuation technique in estimating the fair value of proved developed producing reserves, which requires management to apply significant judgment in developing an estimate of an appropriate discount rate, auditing management’s selection of a discount rate required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the selection of the discount rate applied to estimated future net cash flows from proved oil and gas properties included the following, among others:

•With the assistance of our fair value specialists, we evaluated the reasonableness of the discount rate by:

◦Evaluating the appropriateness of the mathematical model used to develop the discount rate

◦Evaluating the guideline public companies selected by management and used in the selection of the discount rate considering the comparability of operations to the Company

◦Comparing the selected discount rate to published discount rate estimates for the industry/asset type

◦Developing a range of independent estimates of the discount rate by independently obtaining information to estimate components of the discount rate, including the cost of debt capital, the cost of equity capital, and debt-to-equity ratio

◦Comparing the discount rate selected by management with the range of independent estimates

◦Recomputing the mathematical accuracy of the calculation of the discount rate

/s/ Deloitte & Touche LLP

Denver, Colorado

February 2624, ~~2020~~2021

We have served as the Company'’s auditor since 2003.

5965

Table of Contents

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

	~~As of December 31,~~		As of December 31,
	2019				2018
			2020					2019
	~~(in thousands, except share data)~~		(in thousands, except share data)
Assets:
Current assets:
Cash and cash equivalents	$	~~16,449~~	$	24,709	$	~~32,774~~		$	16,449
Accounts receivable, net of allowance for doubtful accounts	62,120				72,943
Accounts receivable, net of allowance			38,294					62,120
Derivative assets	~~3,916~~		18,477		~~81,166~~			3,916
Prepayments and other current assets	~~3,952~~		8,748		~~2,898~~			3,952
Total current assets	~~86,437~~		90,228		~~189,781~~			86,437
Property and equipment — at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	~~2,644,129~~		2,763,968		~~2,195,310~~			2,644,129
Unproved oil and gas properties, excluded from amortization	~~357,793~~		212,550		~~468,208~~			357,793
Furniture, equipment and other	~~29,804~~		30,403		~~20,662~~			29,804
	3,031,726				2,684,180
			3,006,921					3,031,726
Accumulated depreciation, depletion, amortization and impairment	~~(967,552~~		(2,282,740)		~~(654,657~~		)	(967,552)
Total property and equipment, net	~~2,064,174~~		724,181		~~2,029,523~~			2,064,174
Derivative assets	—				27,289
Other noncurrent assets			12,228					5,441
Other noncurrent assets	5,441				5,867
Total			$	826,637				$	2,156,052
Total	$	2,156,052			$	2,252,460
Liabilities and Stockholders' Equity:
Liabilities and Stockholders' Equity:
Current liabilities:
Current liabilities:
Accounts payable and accrued liabilities			$	31,920				$	71,638
Accounts payable and accrued liabilities	$	71,638			$	131,379
Amounts payable to oil and gas property owners			28,616					37,922
Amounts payable to oil and gas property owners	37,922				55,792
Production taxes payable			22,221					61,507
Production taxes payable	61,507				59,155
Derivative liabilities			1,414					4,411
Derivative liabilities	4,411				—
Total current liabilities			84,171					175,478
Current portion of long-term debt	—				1,859
Long-term debt, net of debt issuance costs			760,434					758,911
Total current liabilities	175,478				248,185
Asset retirement obligations			24,825					23,491
Long-term debt, net of debt issuance costs	758,911				617,387
Deferred income taxes			1,556					97,418
Asset retirement obligations	23,491				27,330
Other noncurrent liabilities			32,334					17,436
Deferred income taxes	97,418				139,534
Commitments and contingencies (Note 14)
Other noncurrent liabilities	17,436				7,926
Stockholders’ equity:
Commitments and contingencies (Note 14)
Common stock, 0.001 par value; authorized 8,000,000 shares; 4,305,075 and 4,273,391 shares issued and outstanding at December 31, 2020 and 2019, respectively, with 58,668 and 59,369 shares subject to restrictions, respectively			4					4
Stockholders' equity:
Additional paid-in capital			1,781,966					1,777,986
Common stock, $0.001 par value; authorized 400,000,000 shares; 213,669,597 and 212,477,101 shares issued and outstanding at December 31, 2019 and 2018, respectively, with 2,968,497 and 2,912,166 shares subject to restrictions, respectively	211				210
Accumulated deficit			(1,858,653)					(694,672)
Additional paid-in capital	1,777,779				1,771,730
Treasury stock, at cost: zero shares at December 31, 2020 and 2019			—					—
Retained earnings (accumulated deficit)	(694,672		)		(559,842		)
Total stockholders’ equity (deficit)			(76,683)					1,083,318
Treasury stock, at cost: zero shares at December 31, 2019 and 2018	—				—
Total			$	826,637				$	2,156,052
Total stockholders' equity	1,083,318				1,212,098
Total	$	2,156,052			$	2,252,460

See notes to Consolidated Financial Statements.

6066

Table of Contents

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

	~~Year Ended December 31,~~		Year Ended December 31,
	2019				2018			2017
			2020					2019			2018
	~~(in thousands, except share and pershare data)~~		(in thousands, except share and pershare data)
Operating Revenues
Operating Revenues:
Oil, gas and NGL production	$	~~452,274~~	$	249,192	$	~~452,917~~		$	~~251~~452,~~215~~274		$	452,917
Other operating revenues, net	~~385~~		1,155		~~100~~			~~1,624~~385			100
Total operating revenues	~~452,659~~		250,347		~~453,017~~			~~252~~452,~~839~~659			453,017
Operating Expenses
Operating Expenses:
Lease operating expense	~~37,796~~		32,548		~~27,850~~			2437,~~223~~796			27,850
Gathering, transportation and processing expense	~~10,685~~		18,467		~~4,644~~			210,~~615~~685			4,644
Production tax expense	~~23,541~~		(630)		~~36,762~~			1423,~~476~~541			36,762
Exploration expense	~~143~~		192		70			83143			70
Impairment and abandonment expense	~~9,642~~		1,285,085		~~719~~			499,~~553~~642			719
(Gain) loss on sale of properties	2,901				1,046			(92		)
Loss on sale of properties			4,777					2,901			1,046
Depreciation, depletion and amortization	~~321,276~~		148,995		~~228,480~~			~~159~~321,~~964~~276			228,480
Unused commitments	~~17,706~~		18,807		~~18,187~~			1817,~~231~~706			18,187
General and administrative expense	~~44,759~~		43,167		~~45,130~~			4244,~~476~~759			45,130
Merger transaction expense	~~4,492~~		25,891		~~7,991~~			84,~~749~~492			7,991
Other operating expenses, net	402				1,273			(1,514		)
Other operating expenses (income), net			(544)					402			1,273
Total operating expenses	~~473,343~~		1,576,755		~~372,152~~			~~318~~473,~~764~~343			372,152
Operating Income (Loss)	~~(20,684~~		(1,326,408)		~~80,865~~			(6520,~~925~~684)		)	80,865
Other Income and Expense:
Interest and other income	~~791~~		449		~~1,793~~			~~1,359~~791			1,793
Interest expense	~~(58,100~~		(58,809)		~~(52,703~~		)	(5758,~~710~~100)		)	(52,703)
Commodity derivative gain (loss)	~~(98,953~~		)124,925		~~93,349~~			(998,~~112~~953)		)	93,349
Gain (loss) on extinguishment of debt	—				(257		)	(8,239		)
Loss on extinguishment of debt			—					—			(257)
Total other income (expense)	~~(156,262~~		)66,565		~~42,182~~			(73156,~~702~~262)		)	42,182
Income (Loss) before Income Taxes	~~(176,946~~		(1,259,843)		~~123,047~~			(~~139~~176,~~627~~946)		)	123,047
(Provision for) Benefit from Income Taxes	~~42,116~~		95,862		~~(1,827~~		)	142,~~402~~116			(1,827)
Net Income (Loss)	$	~~(134,830~~	)$	(1,163,981)	$	~~121,220~~		$	(~~138~~134,~~225~~830)	)	$	121,220
Net Income (Loss) Per Common Share, Basic	$	~~(0.64~~	)$	(274.65)	$	~~0.64~~		$	(132.8004)	)	$	32.19
Net Income (Loss) Per Common Share, Diluted	$	~~(0.64~~	)$	(274.65)	$	~~0.64~~		$	(132.8004)	)	$	32.03
Weighted Average Common Shares Outstanding, Basic	~~210,391,669~~		4,238,180		~~188,299,074~~			764,~~858~~207,~~815~~833			3,765,981
Weighted Average Common Shares Outstanding, Diluted	~~210,391,669~~		4,238,180		~~189,241,036~~			764,~~858~~207,~~815~~833			3,784,821

See notes to Consolidated Financial Statements.

6167

Table of Contents

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	~~Year Ended December 31,~~		Year Ended December 31,
	2019				2018			2017
			2020					2019			2018
	~~(in thousands)~~		(in thousands)
Operating Activities:
Net Income (Loss)	$	~~(134,830~~	)$	(1,163,981)	$	~~121,220~~		$	(~~138~~134,~~225~~830)	)	$	121,220
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	~~321,276~~		148,995		~~228,480~~			~~159~~321,~~964~~276			228,480
Deferred income taxes	~~(42,116~~		(95,862)		~~1,827~~			—(42,116)			1,827
Impairment and abandonment expense	~~9,642~~		1,285,085		~~719~~			499,~~553~~642			719
Commodity derivative (gain) loss	~~98,953~~		(124,925)		~~(93,349~~		)	998,~~112~~953			(93,349)
Settlements of commodity derivatives	~~10,667~~		109,583		~~(47,587~~		)	1910,~~099~~667			(47,587)
Stock compensation and other non-cash charges	~~11,306~~		3,821		~~8,337~~			611,~~596~~306			8,337
Amortization of deferred financing costs	~~2,556~~		3,936		~~2,365~~			2,~~194~~556			2,365
(Gain) loss on extinguishment of debt	—				257			8,239
Loss on extinguishment of debt			—					—			257
(Gain) loss on sale of properties	2,901				1,046			(92		)
Loss on sale of properties			4,777					2,901			1,046
Change in operating assets and liabilities:
Accounts receivable	~~10,795~~		16,890		~~(13,697~~		)	~~(18~~10,~~578~~795		)	(13,697)
Prepayments and other assets	~~(27~~		(5,324)		~~(793~~		)	(~~1,848~~27)		)	(793)
Accounts payable, accrued and other liabilities	~~3,030~~		(21,320)		~~(40,324~~		)	113,~~690~~030			(40,324)
Amounts payable to oil and gas property owners	~~(17,870~~		(9,306)		~~34,499~~			10(17,~~402~~870)			34,499
Production taxes payable	~~2,352~~		(23,407)		~~28,441~~			32,~~884~~352			28,441
Net cash provided by (used in) operating activities	278,635				231,441			121,990
Net cash provided by operating activities			128,962					278,635			231,441
Investing Activities:
Additions to oil and gas properties, including acquisitions	~~(426,416~~		(122,857)		~~(453,616~~		)	(~~239~~426,~~631~~416)		)	(453,616)
Additions of furniture, equipment and other	~~(4,662~~		(931)		~~(853~~		)	(~~926~~4,662)		)	(853)
Repayment of debt associated with merger, net of cash acquired	—				(53,357		)	—
Repayment of debt associated with 2018 Merger, net of cash acquired			—					—			(53,357)
Proceeds from sale of properties	~~1,334~~		2,765		~~(221~~		)	~~101~~1,~~845~~334			(221)
Other investing activities	~~(1,612~~		)1,164		~~364~~			(~~299~~1,612)		)	364
Net cash provided by (used in) investing activities	(431,356		)		(507,683		)	(139,011		)
Net cash used in investing activities			(119,859)					(431,356)			(507,683)
Financing Activities:
Proceeds from debt	~~222,000~~		120,000		—			~~275~~222,000			—
Principal and redemption premium payments on debt	(83,859		)		(469		)	(322,343		)
Principal payments on debt			(120,000)					(83,859)			(469)
Proceeds from sale of common stock, net of offering costs	1				1			110,710
Other financing activities			(843)					(1,745)			(4,981)
Other financing activities	(1,746		)		(4,982		)	(7,721		)
Net cash provided by (used in) financing activities			(843)					136,396			(5,450)
Net cash provided by (used in) financing activities	136,396				(5,450		)	55,646
Increase (Decrease) in Cash and Cash Equivalents			8,260					(16,325)			(281,692)
Increase (Decrease) in Cash and Cash Equivalents	(16,325		)		(281,692		)	38,625
Beginning Cash and Cash Equivalents			16,449					32,774			314,466
Beginning Cash and Cash Equivalents	32,774				314,466			275,841
Ending Cash and Cash Equivalents			$	24,709				$	16,449		$	32,774
Ending Cash and Cash Equivalents	$	16,449			$	32,774		$	314,466

See notes to Consolidated Financial Statements.

6268

Table of Contents

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS'’ EQUITY (DEFICIT)

(In thousands)

	~~CommonStock~~		CommonStock		~~AdditionalPaid-InCapital~~			~~RetainedEarnings(AccumulatedDeficit)~~AdditionalPaid-InCapital			~~TreasuryStock~~		AccumulatedDeficit		~~TotalStockholders'Equity~~			TreasuryStock		TotalStockholders’Equity (Deficit)
Balance at December 31, 2016	$	74			$	1,113,797		$	(542,328	)	$	—			$	571,543
Balance at January 1, 2018			$	2				$	1,279,614				$	(681,062)				$	—	$	598,554
Cumulative effect of accounting change	—				180			(509		)	—				(329		)
Restricted stock activity and shares exchanged for tax withholding			—					1					—					(1,535)		(1,534)
Restricted stock activity and shares exchanged for tax withholding	1				—			—			(1,253		)		(1,252		)
Stock-based compensation (1)			—					9,858					—					—		9,858
Stock-based compensation	—				7,099			—			—				7,099
Retirement of treasury stock			—					(1,535)					—					1,535		—
Retirement of treasury stock	—				(1,253		)	—			1,253				—
Issuance of common stock, 2018 Merger			2					483,998					—					—		484,000
Exchange of senior notes for shares of common stock	11				48,981			—			—				48,992
Net income (loss)			—					—					121,220					—		121,220
Issuance of common stock, net of offering costs	23				110,703			—			—				110,726
Balance at December 31, 2018			4					1,771,936					(559,842)					—		1,212,098
Net income (loss)	—				—			(138,225		)	—				(138,225		)
Restricted stock activity and shares exchanged for tax withholding			—					1					—					(1,729)		(1,728)
Balance at December 31, 2017	109				1,279,507			(681,062		)	—				598,554
Stock-based compensation			—					7,778					—					—		7,778
Restricted stock activity and shares exchanged for tax withholding	1				—			—			(1,535		)		(1,534		)
Retirement of treasury stock			—					(1,729)					—					1,729		—
Stock-based compensation (1)	—				9,858			—			—				9,858
Net income (loss)			—					—					(134,830)					—		(134,830)
Retirement of treasury stock	—				(1,535		)	—			1,535				—
Balance at December 31, 2019			4					1,777,986					(694,672)					—		1,083,318
Issuance of common stock, merger	100				483,900			—			—				484,000
Restricted stock activity and shares exchanged for tax withholding			—					—					—					(669)		(669)
Net income (loss)	—				—			121,220			—				121,220
Stock-based compensation			—					4,649					—					—		4,649
Balance at December 31, 2018	210				1,771,730			(559,842		)	—				1,212,098
Retirement of treasury stock			—					(669)					—					669		—
Restricted stock activity and shares exchanged for tax withholding	1				—			—			(1,729		)		(1,728		)
Net income (loss)			—					—					(1,163,981)					—		(1,163,981)
Stock-based compensation	—				7,778			—			—				7,778
Balance at December 31, 2020			$	4				$	1,781,966				$	(1,858,653)				$	—	$	(76,683)
Retirement of treasury stock	—				(1,729		)	—			1,729				—
Net income (loss)	—				—			(134,830		)	—				(134,830		)
Balance at December 31, 2019	$	211			$	1,777,779		$	(694,672	)	$	—			$	1,083,318

See notes to Consolidated Financial Statements.

(1)Includes ~~As of December 31, 2018, includes~~ the modification of the 2016 Program and 2017 Program from performance-based liability awards to service-based equity awards. See Note 11 for additional information.

6369

Table of Contents

HIGHPOINT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, ~~2019~~2020, ~~2018~~2019 and ~~2017~~2018

1. Organization

HighPoint Resources Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the "“Company"” or “HighPoint”), is an independent oil and gas company engaged in the exploration, development and production of oil, natural gas and natural gas liquids ("“NGLs"”). The Company became the successor to Bill Barrett Corporation ("“Bill Barrett"”), on March 19, 2018, upon closing of the transactions contemplated by the Agreement and Plan of Merger, dated December 4, 2017 (the "“2018 Merger Agreement"”), pursuant to which Bill Barrett combined with Fifth Creek Energy Operating Company, LLC ("“Fifth Creek"”) (the "“2018 Merger"”). As a result of the 2018 Merger, Bill Barrett became a wholly-owned subsidiary of HighPoint Resources Corporation and subsequently Bill Barrett changed its name to HighPoint Operating Corporation. The Company currently conducts its activities principally in the Denver Julesburg Basin ("“DJ Basin"”) in Colorado. Except where the context indicates otherwise, references herein to the "“Company"” with respect to periods prior to the completion of the 2018 Merger refer to Bill Barrett and its subsidiaries.

On November 9, 2020, the Company and Bonanza Creek Energy, Inc., a Delaware corporation (“Bonanza Creek”), entered into a definitive merger agreement (“Merger Agreement”) to effectuate the strategic combination of Bonanza Creek and HighPoint (“Merger”). The transaction has been unanimously approved by the board of directors of each company. Under the terms of the Merger Agreement, Bonanza Creek has commenced a registered offer to exchange HighPoint’s senior unsecured notes (the “HighPoint Notes”) for senior notes and common stock of Bonanza Creek (the “Exchange Offer”). The Exchange Offer is conditioned on a minimum participation condition of not less than 97.5% of the aggregate outstanding principal amount of each series of HighPoint Notes being validly tendered in accordance with the terms of the Exchange Offer prior to the expiration date of the Exchange Offer (the “Minimum Participation Condition”). Registration statements on Form S-4 of Bonanza Creek and a merger proxy of HighPoint have been declared effective by the SEC. The Exchange Offer expires on March 11, 2021 (unless extended by HighPoint and Bonanza Creek) and special meetings for Bonanza Creek and HighPoint stockholders will both be held on March 12, 2021 to approve the Merger.

2. Summary of Significant Accounting Policies

Basis of Presentation. The accompanying Consolidated Financial Statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("“GAAP"”). All intercompany accounts and transactions have been eliminated in consolidation.

~~Use~~On ofOctober ~~Estimates.~~20, In2020, the ~~course~~Company ofannounced ~~preparing~~a reverse stock split of the Company'’s ~~financial~~outstanding ~~statements~~shares inof ~~accordance~~common ~~with~~stock ~~GAAP,~~at ~~management~~a ~~makes~~ratio ~~various~~of ~~assumptions,~~1-for-50 ~~judgments~~ and ~~estimates~~a toproportionate ~~determine~~reduction of the ~~reported~~total ~~amount~~number of ~~assets,~~authorized ~~liabilities~~shares of common stock, ~~revenues~~which ~~and~~was ~~expenses~~approved ~~and~~by inthe stockholders at the ~~disclosure~~Company’s Annual Meeting of ~~commitments~~Stockholders ~~and~~on ~~contingencies~~April 28, 2020. ~~Changes~~The inreverse ~~these~~stock ~~assumptions~~split became effective on October 30, ~~judgments~~2020, and ~~estimates~~the ~~will~~Company’s ~~occur~~common asstock was traded on a ~~result~~split-adjusted ofbasis on the ~~passage~~New ofYork ~~time~~Stock ~~and~~Exchange (“NYSE”) at the ~~occurrence~~market ofopen ~~future~~on ~~events~~that ~~and,~~date. ~~accordingly,~~The ~~actual~~par ~~results~~value ~~could~~of ~~differ~~the ~~from~~common ~~amounts~~stock ~~initially~~was ~~established.~~not adjusted as a result of

Areas requiring the use of assumptions, judgments and estimates relate to volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization ("DD&A"), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining the fair values of assets acquired and liabilities assumed in business combinations, asset retirement obligations, the timing of dry hole costs, impairments of proved and unproved properties, valuing deferred tax assets and estimating fair values of derivative instruments and stock-based payment awards.70

Accounts Receivable. Accounts receivable is comprised of the following:

	As of December 31,
	2019			2018
	(in thousands)
Accrued oil, gas and NGL sales	$	50,171		$	44,860
Due from joint interest owners	9,551			27,435
Other	2,419			754
Allowance for doubtful accounts	(21		)	(106		)
Total accounts receivable	$	62,120		$	72,943

Oil and Gas Properties. The Company's oil, gas and NGL exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and remain within cash flows from investing activities in the Consolidated Statements of Cash Flows. If an exploratory well does find proved reserves, the costs remain capitalized and are included within additions to oil and gas properties and remain within cash flows from investing activities in the Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether proved reserves are added

Table of Contents

orthe ~~not~~reverse stock split. ~~Oil~~All share and ~~gas~~per ~~lease~~share ~~acquisition~~amounts ~~costs~~were ~~are~~retroactively ~~also~~adjusted ~~capitalized.~~for

Filing Compare · HighPoint Resources Corp