P15Yfalse--12-31FY20190001690769Alta Mesa Resources, Inc. /DE1250000010714285138888899375000714285762500000.00010.0001120000000028000000012000000002800000001800722272021695761827749521999879761800722271827749520.0050.0051700000170000011700000154000000.00010.0001100000010000001000000100000031312110.33330.33330.33330.33330.33330.3333P7Y 0001690769 2019-01-01 2019-12-31 0001690769 us-gaap:CommonClassCMember 2020-01-31 0001690769 us-gaap:CommonClassAMember 2020-01-31 0001690769 2019-06-28 0001690769 2018-01-01 2018-02-08 0001690769 2018-02-09 2018-12-31 0001690769 srt:NaturalGasLiquidsReservesMember 2019-01-01 2019-12-31 0001690769 amr:MidstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:ProductAndServiceOtherMember 2018-02-09 2018-12-31 0001690769 srt:NaturalGasLiquidsReservesMember 2018-01-01 2018-02-08 0001690769 srt:NaturalGasLiquidsReservesMember 2018-02-09 2018-12-31 0001690769 us-gaap:ProductMember 2018-01-01 2018-02-08 0001690769 us-gaap:ProductMember 2018-02-09 2018-12-31 0001690769 srt:OilReservesMember 2018-01-01 2018-02-08 0001690769 srt:NaturalGasReservesMember 2019-01-01 2019-12-31 0001690769 srt:NaturalGasReservesMember 2018-02-09 2018-12-31 0001690769 amr:MidstreamMember 2018-01-01 2018-02-08 0001690769 us-gaap:ProductAndServiceOtherMember 2019-01-01 2019-12-31 0001690769 srt:NaturalGasReservesMember 2018-01-01 2018-02-08 0001690769 us-gaap:ProductAndServiceOtherMember 2018-01-01 2018-02-08 0001690769 amr:MidstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:ProductMember 2019-01-01 2019-12-31 0001690769 srt:OilReservesMember 2019-01-01 2019-12-31 0001690769 srt:OilReservesMember 2018-02-09 2018-12-31 0001690769 2018-12-31 0001690769 us-gaap:PreferredClassBMember 2018-12-31 0001690769 2019-12-31 0001690769 us-gaap:CommonClassAMember 2018-12-31 0001690769 us-gaap:PreferredClassAMember 2019-12-31 0001690769 us-gaap:CommonClassAMember 2019-12-31 0001690769 us-gaap:PreferredClassAMember 2018-12-31 0001690769 us-gaap:PreferredClassBMember 2019-12-31 0001690769 us-gaap:CommonClassCMember 2018-12-31 0001690769 us-gaap:CommonClassCMember 2019-12-31 0001690769 2017-12-31 0001690769 2018-02-09 0001690769 2018-02-08 0001690769 us-gaap:NoncontrollingInterestMember 2019-01-01 2019-12-31 0001690769 us-gaap:AdditionalPaidInCapitalMember 2018-12-31 0001690769 us-gaap:ParentMember 2018-02-09 2018-12-31 0001690769 us-gaap:ParentMember 2018-02-08 0001690769 us-gaap:AdditionalPaidInCapitalMember 2019-01-01 2019-12-31 0001690769 2018-02-09 2018-02-09 0001690769 us-gaap:ParentMember 2018-02-09 2018-02-09 0001690769 us-gaap:NoncontrollingInterestMember 2018-02-09 2018-12-31 0001690769 us-gaap:ParentMember 2018-02-09 0001690769 us-gaap:CommonClassAMember us-gaap:CommonStockMember 2018-02-08 0001690769 us-gaap:NoncontrollingInterestMember 2018-02-09 2018-02-09 0001690769 us-gaap:CommonClassCMember us-gaap:CommonStockMember 2019-12-31 0001690769 us-gaap:NoncontrollingInterestMember 2018-02-09 0001690769 us-gaap:CommonClassCMember us-gaap:CommonStockMember 2018-12-31 0001690769 us-gaap:RetainedEarningsMember 2018-02-08 0001690769 us-gaap:CommonClassCMember us-gaap:CommonStockMember 2018-02-09 0001690769 us-gaap:CommonClassAMember us-gaap:CommonStockMember 2018-02-09 2018-02-09 0001690769 us-gaap:CommonClassBMember us-gaap:CommonStockMember 2018-02-08 0001690769 us-gaap:AdditionalPaidInCapitalMember 2019-12-31 0001690769 us-gaap:AdditionalPaidInCapitalMember 2018-02-09 2018-12-31 0001690769 us-gaap:RetainedEarningsMember 2018-02-09 2018-12-31 0001690769 us-gaap:NoncontrollingInterestMember 2018-12-31 0001690769 us-gaap:ParentMember 2019-01-01 2019-12-31 0001690769 us-gaap:RetainedEarningsMember 2019-12-31 0001690769 us-gaap:CommonClassAMember us-gaap:CommonStockMember 2019-01-01 2019-12-31 0001690769 us-gaap:CommonClassCMember us-gaap:CommonStockMember 2018-02-09 2018-02-09 0001690769 us-gaap:ParentMember 2019-12-31 0001690769 us-gaap:CommonClassAMember us-gaap:CommonStockMember 2018-12-31 0001690769 us-gaap:AdditionalPaidInCapitalMember 2018-02-09 2018-02-09 0001690769 us-gaap:CommonClassAMember us-gaap:CommonStockMember 2018-02-09 2018-12-31 0001690769 us-gaap:CommonClassCMember us-gaap:CommonStockMember 2018-02-09 2018-12-31 0001690769 us-gaap:CommonClassAMember us-gaap:CommonStockMember 2018-02-09 0001690769 us-gaap:RetainedEarningsMember 2018-02-09 0001690769 us-gaap:NoncontrollingInterestMember 2019-12-31 0001690769 us-gaap:AdditionalPaidInCapitalMember 2018-02-09 0001690769 us-gaap:AdditionalPaidInCapitalMember 2018-02-08 0001690769 us-gaap:CommonClassAMember us-gaap:CommonStockMember 2019-12-31 0001690769 us-gaap:RetainedEarningsMember 2019-01-01 2019-12-31 0001690769 us-gaap:CommonClassBMember us-gaap:CommonStockMember 2018-02-09 2018-02-09 0001690769 us-gaap:RetainedEarningsMember 2018-12-31 0001690769 us-gaap:CommonClassCMember us-gaap:CommonStockMember 2019-01-01 2019-12-31 0001690769 us-gaap:ParentMember 2018-12-31 0001690769 us-gaap:DiscontinuedOperationsDisposedOfBySaleMember amr:UpstreamAssetsMember us-gaap:SubsequentEventMember 2020-01-01 0001690769 us-gaap:DiscontinuedOperationsDisposedOfBySaleMember amr:MidstreamAssetsMember us-gaap:SubsequentEventMember 2020-01-01 0001690769 srt:MinimumMember us-gaap:PropertyPlantAndEquipmentOtherTypesMember 2019-01-01 2019-12-31 0001690769 amr:ProcessingPlantAndPipelinesMember 2019-01-01 2019-12-31 0001690769 srt:MaximumMember us-gaap:PropertyPlantAndEquipmentOtherTypesMember 2019-01-01 2019-12-31 0001690769 amr:CimarronExpressPipelineLLCMember 2019-11-30 0001690769 amr:AltaMesaHoldingsLPMember amr:SeniorNotesOneMember 2018-02-08 0001690769 amr:AltaMesaHoldingsLPMember amr:SeniorNotesOneMember 2019-12-31 0001690769 amr:CompressorsMember 2019-01-01 2019-12-31 0001690769 amr:AltaMesaHoldingsLPMember amr:AltaMesaRBLMember 2019-12-31 0001690769 amr:SeniorNotesOneMember 2019-12-31 0001690769 amr:SeniorNotesOneMember 2019-01-01 2019-12-31 0001690769 us-gaap:SubsequentEventMember 2020-01-15 0001690769 amr:DebtorInPossessionMember 2019-01-01 2019-12-31 0001690769 amr:DebtorInPossessionMember us-gaap:ProductAndServiceOtherMember 2019-01-01 2019-12-31 0001690769 amr:DebtorInPossessionMember srt:NaturalGasReservesMember 2019-01-01 2019-12-31 0001690769 amr:DebtorInPossessionMember srt:NaturalGasLiquidsReservesMember 2019-01-01 2019-12-31 0001690769 amr:DebtorInPossessionMember srt:OilReservesMember 2019-01-01 2019-12-31 0001690769 amr:DebtorInPossessionMember 2018-12-31 0001690769 amr:DebtorInPossessionMember 2019-12-31 0001690769 amr:UpstreamMember 2019-01-01 2019-12-31 0001690769 amr:MidstreamMember 2019-01-01 2019-12-31 0001690769 amr:UpstreamMember us-gaap:SubsequentEventMember 2020-01-01 0001690769 amr:MidstreamMember 2018-01-01 2018-12-31 0001690769 amr:MidstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:LongTermContractWithCustomerMember amr:UpstreamMember 2019-01-01 2019-12-31 0001690769 amr:UpstreamMember 2018-01-01 2018-12-31 0001690769 amr:MidstreamMember 2018-01-01 2018-02-08 0001690769 amr:UpstreamMember 2018-01-01 2018-02-08 0001690769 amr:UpstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:AccountingStandardsUpdate201602Member 2019-01-01 0001690769 us-gaap:OperatingExpenseMember 2019-01-01 2019-12-31 0001690769 us-gaap:GeneralAndAdministrativeExpenseMember 2019-01-01 2019-12-31 0001690769 amr:RelatedPartyReceivablesMember 2018-02-09 2018-12-31 0001690769 amr:RelatedPartyReceivablesMember 2017-12-31 0001690769 us-gaap:TradeAccountsReceivableMember 2019-01-01 2019-12-31 0001690769 amr:RelatedPartyReceivablesMember 2018-01-01 2018-02-08 0001690769 us-gaap:TradeAccountsReceivableMember 2018-12-31 0001690769 us-gaap:TradeAccountsReceivableMember 2018-02-09 2018-12-31 0001690769 us-gaap:TradeAccountsReceivableMember 2018-02-08 0001690769 amr:RelatedPartyReceivablesMember 2019-01-01 2019-12-31 0001690769 amr:RelatedPartyReceivablesMember 2018-02-08 0001690769 amr:RelatedPartyReceivablesMember 2018-12-31 0001690769 us-gaap:TradeAccountsReceivableMember 2018-01-01 2018-02-08 0001690769 us-gaap:TradeAccountsReceivableMember 2017-12-31 0001690769 amr:RelatedPartyReceivablesMember 2019-12-31 0001690769 us-gaap:TradeAccountsReceivableMember 2019-12-31 0001690769 amr:HighMesaAgreementMember 2018-12-31 0001690769 amr:HighMesaAgreementMember 2019-01-01 2019-12-31 0001690769 amr:HighMesaAgreementMember 2019-12-31 0001690769 amr:SeniorNotesTwoMember amr:HighMesaServicesLlcMember 2019-12-31 0001690769 srt:AffiliatedEntityMember 2019-12-31 0001690769 amr:HighMesaAgreementMember srt:AffiliatedEntityMember 2019-12-31 0001690769 amr:HighMesaAgreementMember srt:AffiliatedEntityMember 2018-12-31 0001690769 amr:NorthwestGasProcessingMember 2019-12-31 0001690769 amr:SeniorNotesTwoMember amr:HighMesaServicesLlcMember 2018-12-31 0001690769 amr:NorthwestGasProcessingMember 2018-12-31 0001690769 us-gaap:CommonClassAMember 2018-02-09 2018-12-31 0001690769 us-gaap:CommonClassAMember 2019-01-01 2019-12-31 0001690769 us-gaap:WarrantMember 2019-01-01 2019-12-31 0001690769 us-gaap:CommonClassCMember 2018-02-09 2018-12-31 0001690769 amr:StockOptionsRestrictedStockAndRestrictedUnitsMember 2018-02-09 2018-12-31 0001690769 amr:StockOptionsRestrictedStockAndRestrictedUnitsMember 2019-01-01 2019-12-31 0001690769 us-gaap:CommonClassCMember 2019-01-01 2019-12-31 0001690769 us-gaap:WarrantMember 2018-02-09 2018-12-31 0001690769 amr:KingfisherMidstreamLLCMember 2019-01-01 2019-12-31 0001690769 amr:AltaMesaHoldingsLPMember 2019-01-01 2019-12-31 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:VolumeWeightedAveragePriceThreeMember 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:VolumeWeightedAveragePriceTwoMember 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:VolumeWeightedAveragePriceOneMember 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:VolumeWeightedAveragePriceFourMember 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:KingfisherMidstreamLLCMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:HighMesaHoldingsLpMember amr:AltaMesaHoldingsLPMember 2018-02-09 2018-02-09 0001690769 amr:KfmHoldcoLlcMember 2018-04-01 2018-06-30 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:AltaMesaAltaMesaGpAndKingfisherMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember us-gaap:CommonClassAMember 2018-01-01 2018-12-31 0001690769 amr:FenterEnergyLLCMember 2018-10-01 2018-10-31 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:CommonUnitsMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:AltaMesaHoldingsGpLlcMember 2018-02-09 0001690769 amr:RiverstoneViSrIiHoldingsL.p.Member us-gaap:CommonClassAMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:RiverstoneContributorAgreementMember amr:AltaMesaHoldingsLPMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:KingfisherMidstreamLLCMember 2018-02-09 0001690769 us-gaap:CommonClassCMember 2018-02-09 0001690769 us-gaap:CommonClassAMember 2018-01-01 2018-12-31 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember us-gaap:CommonClassAMember 2018-01-01 2019-12-31 0001690769 amr:AltaMesaHoldingsGpLlcMember 2018-02-09 2018-02-09 0001690769 amr:MinorityVotingInterestHoldersInAltaMesaGpMember 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:KfmHoldcoLlcMember 2018-02-09 2018-02-09 0001690769 amr:HighMesaHoldingsLpMember 2018-04-01 2018-06-30 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:AltaMesaHoldingsLPMember 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:AltaMesaHoldingsLPMember 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember 2019-12-31 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:KingfisherMidstreamLLCMember 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember us-gaap:CommonClassAMember 2019-01-01 2019-12-31 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember 2019-12-31 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:AltaMesaHoldingsLPMember 2018-02-09 2018-02-09 0001690769 amr:KingfisherMidstreamLLCMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:HighMesaHoldingsLpMember amr:VolumeWeightedAveragePriceOneMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:HighMesaHoldingsLpMember amr:VolumeWeightedAveragePriceFourMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:KfmHoldcoLlcMember amr:VolumeWeightedAveragePriceOneMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:HighMesaHoldingsLpMember amr:VolumeWeightedAveragePriceTwoMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:KfmHoldcoLlcMember amr:VolumeWeightedAveragePriceTwoMember 2018-02-09 2018-02-09 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:HighMesaHoldingsLpMember amr:VolumeWeightedAveragePriceThreeMember 2018-02-09 2018-02-09 0001690769 amr:KingfisherMidstreamLLCMember srt:AffiliatedEntityMember 2018-11-01 2018-11-30 0001690769 amr:KingfisherMidstreamLLCMember srt:AffiliatedEntityMember 2018-11-30 0001690769 amr:NotesPayableToFounderMember 2018-01-01 2018-02-08 0001690769 amr:NotesPayableToFounderMember 2017-12-31 0001690769 amr:WeeksIslandLouisianaMember us-gaap:DiscontinuedOperationsDisposedOfBySaleMember amr:NonStackAssetsMember 2018-01-01 2018-02-08 0001690769 amr:AltaMesaHoldingsLPMember amr:SeniorNotesOneMember us-gaap:EstimateOfFairValueFairValueDisclosureMember 2019-12-31 0001690769 amr:AltaMesaHoldingsLPMember amr:SeniorNotesOneMember us-gaap:EstimateOfFairValueFairValueDisclosureMember 2018-12-31 0001690769 us-gaap:CarryingReportedAmountFairValueDisclosureMember amr:MidstreamMember 2018-12-31 0001690769 us-gaap:EstimateOfFairValueFairValueDisclosureMember amr:MidstreamMember 2019-12-31 0001690769 us-gaap:ChangeDuringPeriodFairValueDisclosureMember amr:MidstreamMember 2019-12-31 0001690769 us-gaap:ChangeDuringPeriodFairValueDisclosureMember amr:MidstreamMember 2018-12-31 0001690769 us-gaap:CarryingReportedAmountFairValueDisclosureMember amr:MidstreamMember 2019-12-31 0001690769 us-gaap:EstimateOfFairValueFairValueDisclosureMember amr:MidstreamMember 2018-12-31 0001690769 amr:DerivativeLiabilitiesNonCurrentMember 2018-12-31 0001690769 amr:DerivativeLiabilitiesCurrentMember 2018-12-31 0001690769 amr:ContractsTobeSettledJanuary2019Member 2018-12-31 0001690769 amr:AltaMesaRBLMember 2019-09-01 2019-09-30 0001690769 us-gaap:NondesignatedMember 2019-01-01 2019-12-31 0001690769 amr:CommodityContractNaturalGasMember us-gaap:NondesignatedMember 2019-01-01 2019-12-31 0001690769 amr:CommodityContractNaturalGasMember us-gaap:NondesignatedMember 2018-01-01 2018-02-08 0001690769 amr:CommodityContractOilMember us-gaap:NondesignatedMember 2018-01-01 2018-02-08 0001690769 amr:CommodityContractNaturalGasMember us-gaap:NondesignatedMember 2018-02-09 2018-12-31 0001690769 amr:CommodityContractOilMember us-gaap:NondesignatedMember 2018-02-09 2018-12-31 0001690769 us-gaap:NondesignatedMember 2018-02-09 2018-12-31 0001690769 amr:CommodityContractOilMember us-gaap:NondesignatedMember 2019-01-01 2019-12-31 0001690769 us-gaap:NondesignatedMember 2018-01-01 2018-02-08 0001690769 amr:DerivativeAssetsCurrentMember 2018-12-31 0001690769 amr:DerivativeAssetNonCurrentMember 2018-12-31 0001690769 2019-11-13 2019-11-13 0001690769 2019-01-01 2019-11-13 0001690769 2019-11-13 0001690769 amr:CimarronExpressMember 2018-01-01 2018-12-31 0001690769 2019-11-01 2019-11-30 0001690769 srt:MaximumMember 2018-01-01 2018-02-08 0001690769 srt:MinimumMember 2018-01-01 2018-02-08 0001690769 amr:SeniorNotesOneMember 2018-12-31 0001690769 amr:AltaMesaHoldingsLPMember amr:AltaMesaRBLMember 2018-12-31 0001690769 amr:KingfisherMidstreamLLCMember 2018-12-31 0001690769 amr:KingfisherMidstreamLLCMember 2019-12-31 0001690769 amr:AltaMesaCreditFacilityMember 2019-01-01 2019-12-31 0001690769 srt:MinimumMember amr:KingfisherCreditFacilityMember us-gaap:EurodollarMember 2019-01-01 2019-12-31 0001690769 amr:AltaMesaCreditFacilityMember 2019-04-30 0001690769 amr:AltaMesaCreditFacilityMember 2018-02-09 0001690769 amr:AltaMesaCreditFacilityMember 2019-12-31 0001690769 amr:AltaMesaHoldingsLPMember 2018-04-30 0001690769 amr:KingfisherCreditFacilityMember 2019-12-31 0001690769 srt:MinimumMember amr:AltaMesaCreditFacilityMember us-gaap:EurodollarMember 2019-01-01 2019-12-31 0001690769 amr:AltaMesaCreditFacilityMember 2019-08-31 0001690769 srt:MaximumMember amr:KingfisherCreditFacilityMember us-gaap:EurodollarMember 2019-01-01 2019-12-31 0001690769 srt:MaximumMember amr:AltaMesaCreditFacilityMember us-gaap:EurodollarMember 2019-01-01 2019-12-31 0001690769 amr:AltaMesaCreditFacilityMember us-gaap:EurodollarMember 2019-01-01 2019-12-31 0001690769 amr:KingfisherMidstreamLLCMember amr:KingfisherCreditFacilityMember 2019-12-31 0001690769 us-gaap:SeniorNotesMember 2019-12-31 0001690769 amr:AmendmentToKFMCreditFacilityMember 2019-12-31 0001690769 amr:KingfisherCreditFacilityMember us-gaap:FederalFundsEffectiveSwapRateMember 2019-01-01 2019-12-31 0001690769 amr:AltaMesaCreditFacilityMember us-gaap:FederalFundsEffectiveSwapRateMember 2019-01-01 2019-12-31 0001690769 amr:MidstreamMember 2019-12-31 0001690769 amr:UpstreamMember 2019-12-31 0001690769 amr:KingfisherMidstreamLLCMember srt:NaturalGasReservesMember 2019-01-01 2019-12-31 0001690769 amr:KingfisherMidstreamLLCMember 2019-01-01 2019-12-31 0001690769 us-gaap:PerformanceSharesMember 2018-02-09 2018-12-31 0001690769 amr:VestingPeriodOneMember 2019-01-01 2019-12-31 0001690769 amr:VestingPeriodTwoMember 2019-01-01 2019-12-31 0001690769 amr:ArmEnergyManagementLLCMember 2018-01-01 2018-02-08 0001690769 amr:ArmEnergyManagementLLCMember 2019-01-01 2019-12-31 0001690769 amr:ArmEnergyManagementLLCMember 2018-02-09 2018-09-30 0001690769 amr:ArmEnergyManagementLLCMember amr:MarketingFeesMember 2018-01-01 2018-02-08 0001690769 amr:ArmEnergyManagementLLCMember amr:MarketingFeesMember 2019-01-01 2019-12-31 0001690769 amr:ArmEnergyManagementLLCMember amr:MarketingFeesMember 2018-02-09 2018-09-30 0001690769 amr:ArmEnergyManagementLLCMember 2018-12-31 0001690769 amr:ArmEnergyManagementLLCMember 2019-12-31 0001690769 amr:OneCustomerMember us-gaap:SalesRevenueNetMember us-gaap:CustomerConcentrationRiskMember 2019-01-01 2019-12-31 0001690769 amr:PublicWarrantsMember 2019-12-31 0001690769 us-gaap:CommonClassAMember us-gaap:AdditionalPaidInCapitalMember 2018-01-01 2018-12-31 0001690769 amr:KingfisherContributorMember us-gaap:CommonClassCMember 2018-02-09 2018-12-31 0001690769 us-gaap:PrivatePlacementMember 2019-12-31 0001690769 us-gaap:PreferredClassBMember 2019-01-01 2019-12-31 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember 2018-12-31 0001690769 amr:AltaMesaHoldingsGpLlcMember us-gaap:CommonClassBMember 2019-12-31 0001690769 amr:KingfisherContributorMember us-gaap:CommonClassCMember 2019-01-01 2019-12-31 0001690769 us-gaap:PreferredClassAMember 2019-01-01 2019-12-31 0001690769 amr:AltaMesaContributorMember us-gaap:CommonClassAMember 2018-02-09 2018-12-31 0001690769 amr:BayouCityEnergyManagementLLCMember us-gaap:PreferredClassAMember 2019-12-31 0001690769 2018-08-31 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:AltaMesaHoldingsGpLlcMember us-gaap:CommonClassBMember 2019-01-01 2019-12-31 0001690769 amr:ForwardPurchaseWarrantsMember 2019-01-01 2019-12-31 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember amr:AltaMesaHoldingsGpLlcMember us-gaap:CommonClassBMember 2019-12-31 0001690769 amr:AltaMesaContributorMember us-gaap:CommonClassAMember 2019-01-01 2019-12-31 0001690769 amr:AltaMesaHoldingsGpLlcMember us-gaap:CommonClassAMember 2019-01-01 2019-12-31 0001690769 us-gaap:CommonClassCMember 2019-01-01 2019-12-31 0001690769 amr:SilverRunAcquisitionCorporationOpcoLpMember us-gaap:CommonClassAMember 2018-02-09 2018-12-31 0001690769 amr:KingfisherContributorMember us-gaap:CommonClassAMember 2018-02-09 2018-12-31 0001690769 us-gaap:RestrictedStockMember 2019-01-01 2019-12-31 0001690769 us-gaap:RestrictedStockMember 2018-02-09 2018-12-31 0001690769 us-gaap:RestrictedStockMember 2018-12-31 0001690769 us-gaap:RestrictedStockMember 2019-12-31 0001690769 us-gaap:RestrictedStockMember 2018-02-08 0001690769 us-gaap:EmployeeStockOptionMember 2019-01-01 2019-12-31 0001690769 us-gaap:EmployeeStockOptionMember 2018-02-09 2018-12-31 0001690769 amr:RestrictedStockUnitsDirectorsMember 2018-02-09 2018-12-31 0001690769 amr:PerformanceRestrictedStockUnitsMember 2018-02-09 2018-12-31 0001690769 amr:PerformanceRestrictedStockUnitsMember 2019-12-31 0001690769 amr:PerformanceRestrictedStockUnitsMember us-gaap:ShareBasedCompensationAwardTrancheOneMember 2018-02-09 2018-12-31 0001690769 srt:MaximumMember amr:PerformanceRestrictedStockUnitsMember 2018-02-09 2018-12-31 0001690769 amr:PerformanceRestrictedStockUnitsMember 2019-01-01 2019-12-31 0001690769 amr:PerformanceRestrictedStockUnitsMember us-gaap:ShareBasedCompensationAwardTrancheThreeMember 2018-02-09 2018-12-31 0001690769 us-gaap:EmployeeStockOptionMember 2019-12-31 0001690769 amr:PerformanceRestrictedStockUnitsMember us-gaap:ShareBasedCompensationAwardTrancheTwoMember 2018-02-09 2018-12-31 0001690769 srt:MinimumMember amr:PerformanceRestrictedStockUnitsMember 2018-02-09 2018-12-31 0001690769 amr:RestrictedStockUnitsEmployeesMember 2018-02-09 2018-12-31 0001690769 amr:PerformanceRestrictedStockUnitsMember 2018-02-08 0001690769 amr:PerformanceRestrictedStockUnitsMember 2018-12-31 0001690769 us-gaap:EmployeeStockOptionMember us-gaap:ShareBasedCompensationAwardTrancheTwoMember 2019-01-01 2019-12-31 0001690769 us-gaap:EmployeeStockOptionMember us-gaap:ShareBasedCompensationAwardTrancheOneMember 2019-01-01 2019-12-31 0001690769 us-gaap:EmployeeStockOptionMember us-gaap:ShareBasedCompensationAwardTrancheThreeMember 2019-01-01 2019-12-31 0001690769 us-gaap:RestrictedStockMember us-gaap:ShareBasedCompensationAwardTrancheTwoMember 2019-01-01 2019-12-31 0001690769 us-gaap:RestrictedStockMember us-gaap:ShareBasedCompensationAwardTrancheOneMember 2019-01-01 2019-12-31 0001690769 us-gaap:RestrictedStockMember us-gaap:ShareBasedCompensationAwardTrancheThreeMember 2019-01-01 2019-12-31 0001690769 amr:JointDevelopmentAgreementMember amr:BceStackMember 2016-12-31 2016-12-31 0001690769 amr:SeniorNotesTwoMember amr:LongTermNoteReceivableFromHMSMember amr:HighMesaServicesLlcMember 2018-02-01 2018-02-08 0001690769 amr:JointDevelopmentAgreementMember 2016-01-13 0001690769 amr:JointDevelopmentAgreementMember amr:BceStackMember 2019-12-31 0001690769 amr:HighMesaServicesMember 2019-12-31 0001690769 amr:SeniorNotesTwoMember amr:LongTermNoteReceivableFromHMSMember amr:HighMesaServicesLlcMember 2018-02-09 2018-12-31 0001690769 amr:NorthwestGasProcessingMember 2017-09-29 0001690769 amr:CompensationToRelatedPartyMember us-gaap:VicePresidentMember amr:DavidMcclureVpOfFacilitiesAndMidstreamMember 2018-02-09 2018-09-30 0001690769 amr:JointDevelopmentAgreementMember 2016-12-31 2016-12-31 0001690769 amr:CompensationToRelatedPartyMember us-gaap:VicePresidentMember amr:DavidMcclureVpOfFacilitiesAndMidstreamMember 2019-01-01 2019-12-31 0001690769 amr:JointDevelopmentAgreementMember amr:BceStackMember 2016-12-31 0001690769 amr:BceStackMember 2018-12-31 0001690769 amr:HighMesaAgreementMember srt:AffiliatedEntityMember 2019-01-01 2019-12-31 0001690769 amr:SeniorNotesTwoMember 2019-12-31 0001690769 amr:CompensationToRelatedPartyMember us-gaap:VicePresidentMember amr:DavidMcclureVpOfFacilitiesAndMidstreamMember 2018-01-01 2018-02-08 0001690769 us-gaap:IntersegmentEliminationMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember amr:MidstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember amr:UpstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember us-gaap:ProductAndServiceOtherMember amr:UpstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember amr:SegmentOperatingRevenueMember amr:MidstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:IntersegmentEliminationMember srt:OilReservesMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember us-gaap:ProductAndServiceOtherMember amr:MidstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember amr:MidstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember amr:UpstreamMember 2018-12-31 0001690769 us-gaap:IntersegmentEliminationMember us-gaap:ProductMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember srt:OilReservesMember amr:MidstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:IntersegmentEliminationMember srt:NaturalGasReservesMember 2018-02-09 2018-12-31 0001690769 us-gaap:IntersegmentEliminationMember srt:NaturalGasLiquidsReservesMember 2018-02-09 2018-12-31 0001690769 us-gaap:IntersegmentEliminationMember us-gaap:ProductAndServiceOtherMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember srt:NaturalGasLiquidsReservesMember amr:UpstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember srt:NaturalGasLiquidsReservesMember amr:MidstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:IntersegmentEliminationMember amr:SegmentOperatingRevenueMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember amr:UpstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember srt:NaturalGasReservesMember amr:UpstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:IntersegmentEliminationMember 2018-12-31 0001690769 us-gaap:IntersegmentEliminationMember us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember us-gaap:ProductMember amr:UpstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember srt:OilReservesMember amr:UpstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember srt:NaturalGasReservesMember amr:MidstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember amr:SegmentOperatingRevenueMember amr:UpstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember us-gaap:ProductMember amr:MidstreamMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember amr:MidstreamMember 2018-12-31 0001690769 amr:SegmentOperatingRevenueMember 2018-02-09 2018-12-31 0001690769 us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember 2018-02-09 2018-12-31 0001690769 us-gaap:OperatingSegmentsMember amr:UpstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember amr:MidstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:IntersegmentEliminationMember 2019-01-01 2019-12-31 0001690769 us-gaap:IntersegmentEliminationMember srt:NaturalGasLiquidsReservesMember 2019-01-01 2019-12-31 0001690769 us-gaap:IntersegmentEliminationMember us-gaap:ProductAndServiceOtherMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember srt:NaturalGasReservesMember amr:MidstreamMember 2019-01-01 2019-12-31 0001690769 amr:SegmentOperatingRevenueMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember us-gaap:ProductAndServiceOtherMember amr:MidstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:IntersegmentEliminationMember srt:OilReservesMember 2019-01-01 2019-12-31 0001690769 us-gaap:IntersegmentEliminationMember us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember srt:OilReservesMember amr:UpstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember us-gaap:ProductMember amr:UpstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember us-gaap:ProductAndServiceOtherMember amr:UpstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember amr:MidstreamMember 2019-12-31 0001690769 us-gaap:IntersegmentEliminationMember amr:SegmentOperatingRevenueMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember amr:UpstreamMember 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember srt:NaturalGasReservesMember amr:UpstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember amr:MidstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember amr:SegmentOperatingRevenueMember amr:MidstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember amr:UpstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:IntersegmentEliminationMember srt:NaturalGasReservesMember 2019-01-01 2019-12-31 0001690769 us-gaap:IntersegmentEliminationMember 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember srt:NaturalGasLiquidsReservesMember amr:MidstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember srt:NaturalGasLiquidsReservesMember amr:UpstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember us-gaap:ProductMember amr:MidstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember srt:OilReservesMember amr:MidstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:IntersegmentEliminationMember us-gaap:ProductMember 2019-01-01 2019-12-31 0001690769 us-gaap:OperatingSegmentsMember amr:SegmentOperatingRevenueMember amr:UpstreamMember 2019-01-01 2019-12-31 0001690769 us-gaap:IntersegmentEliminationMember us-gaap:AccountingStandardsUpdate201409Member 2018-02-09 2018-12-31 0001690769 amr:BarrelsOfOilEquivalentMember 2017-12-31 0001690769 amr:BarrelsOfOilEquivalentMember 2018-12-31 0001690769 srt:OilReservesMember 2019-12-31 0001690769 srt:NaturalGasLiquidsReservesMember 2018-01-01 2018-02-08 0001690769 srt:NaturalGasLiquidsReservesMember 2017-12-31 0001690769 srt:NaturalGasLiquidsReservesMember 2019-12-31 0001690769 srt:NaturalGasReservesMember 2018-02-08 0001690769 amr:BarrelsOfOilEquivalentMember 2018-02-09 2018-12-31 0001690769 srt:OilReservesMember 2018-02-08 0001690769 srt:NaturalGasReservesMember 2019-01-01 2019-12-31 0001690769 srt:NaturalGasLiquidsReservesMember 2018-02-09 2018-12-31 0001690769 amr:BarrelsOfOilEquivalentMember 2019-01-01 2019-12-31 0001690769 srt:NaturalGasReservesMember 2018-02-09 2018-12-31 0001690769 srt:NaturalGasReservesMember 2018-01-01 2018-02-08 0001690769 srt:OilReservesMember 2018-12-31 0001690769 srt:NaturalGasReservesMember 2019-12-31 0001690769 amr:BarrelsOfOilEquivalentMember 2018-01-01 2018-02-08 0001690769 srt:OilReservesMember 2018-02-09 2018-12-31 0001690769 srt:NaturalGasReservesMember 2017-12-31 0001690769 srt:OilReservesMember 2019-01-01 2019-12-31 0001690769 srt:OilReservesMember 2018-01-01 2018-02-08 0001690769 amr:BarrelsOfOilEquivalentMember 2018-02-08 0001690769 srt:NaturalGasLiquidsReservesMember 2018-02-08 0001690769 srt:NaturalGasReservesMember 2018-12-31 0001690769 srt:OilReservesMember 2017-12-31 0001690769 srt:NaturalGasLiquidsReservesMember 2019-01-01 2019-12-31 0001690769 amr:BarrelsOfOilEquivalentMember 2019-12-31 0001690769 srt:NaturalGasLiquidsReservesMember 2018-12-31 iso4217:USD amr:segment iso4217:USD xbrli:shares xbrli:pure xbrli:shares utreg:Mcfe amr:director utreg:mi amr:vote iso4217:USD utreg:MMcf utreg:MMBTU amr:well utreg:MBbls iso4217:USD utreg:bbl utreg:MMcf utreg:MMBoe

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 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, ~~2018~~2019

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

For the transition period from to

Commission file number: 001-38040

_______________________________________

ALTA MESA RESOURCES, INC.

(Exact name of registrant as specified in its charter)

_______________________________________

Delaware	~~81-4433840~~			81-4433840
(State or other jurisdiction ofincorporation or organization)	~~(I.R.S. EmployerIdentification No.)~~			(I.R.S. EmployerIdentification No.)
15021 Katy Freeway, Suite 400,Houston, Texas	77094
15021 Katy Freeway,	Suite 400,	Houston,	Texas	77094
(Address of principal executive offices)	~~(Zip Code)~~			(Zip Code)

Registrant’s telephone number, including area code: 281-530-0991

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, par value $0.0001 per share	AMR	The NASDAQ Capital Market
Warrants to purchase one share of Class A Common Stock	AMRWW	The NASDAQ Capital Market

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

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 o☐ No x☒

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 o No x~~

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 o ☐ No x ☒

Indicate by check mark whether the registrant (1) has ~~submitted~~filed ~~electronically~~all ~~every~~reports ~~Interactive Data File~~ required to be ~~submitted~~filed ~~pursuant~~by toSection 13 ~~Rule~~or ~~405~~15(d) of ~~Regulation~~the ~~S-T~~Securities ~~(§232.405~~Exchange Act of ~~this~~1934 ~~chapter)~~ during the preceding 12 months (or for such shorter period that the registrant was required to ~~submit~~file such ~~files.~~reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x☒ No o ☐

~~Large~~Indicate ~~accelerated~~by ~~filer~~check xmark ~~Accelerated~~whether ~~filer~~the oregistrant ~~Non~~has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-~~accelerated~~T ~~filer~~(§232.405 oof ~~Smaller~~this ~~reporting~~chapter) ~~company~~during othe ~~Emerging~~preceding ~~growth~~12 ~~company~~months o(or for such shorter period that the registrant was required to submit such files.) Yes ☒ No ☐

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

IfLarge anaccelerated ~~emerging~~filer ~~growth~~☐ ~~company,~~Accelerated ~~indicate~~filer by☐ ~~check~~Non-accelerated ~~mark~~filer if☐ ~~the~~Smaller ~~registrant~~reporting ~~has~~company ~~elected~~☒ ~~not~~Emerging togrowth ~~use~~company ~~the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o~~ ☐

~~Indicate~~If an emerging growth company, indicate by check mark ~~whether~~if the registrant ishas aelected ~~shell~~not ~~company~~to ~~(as~~use ~~defined~~the inextended ~~Rule~~transition ~~12b-2~~period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act). ☐ ~~Yes o No x~~

~~The~~Indicate ~~aggregate~~by ~~market~~check ~~value~~mark ofwhether the ~~voting and non-voting common stock held by non-affiliates of the~~ registrant asis ofa ~~June~~shell ~~28,~~company ~~2018~~ (~~the~~as ~~last~~defined ~~business~~in ~~day~~Rule of12b-2 ~~the registrant’s most recently completed second fiscal quarter) was approximately $776,593,856 based on the closing price~~ of the ~~shares of common stock on that date~~Act). Yes ☐ No ☒

AsThe ofaggregate ~~June 28,~~market ~~2019,~~value ~~there~~of ~~were~~the ~~182,613,382~~voting ~~shares~~and ofnon-voting ~~Class~~common Astock ~~Common~~held ~~Stock~~by ~~and~~non-affiliates ~~199,987,976~~of ~~shares~~the ofregistrant ~~Class~~as Cof ~~Common~~June ~~Stock~~28, ~~par~~2019 ~~value~~(the ~~$0.0001~~last ~~per~~business ~~share~~day ~~outstanding. The shares~~ of ~~Class~~the Aregistrant’s ~~Common~~most ~~Stock~~recently ~~shown~~completed assecond ~~outstanding~~fiscal doquarter) ~~not~~was ~~include 735~~$16,~~855~~522,531 ~~unvested~~based ~~restricted~~on ~~stock~~the ~~awards~~closing ~~outstanding~~price asof the shares of ~~June 28,~~common ~~2019~~stock on that date.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☐ No ☐

As of January 31, 2020, there were 182,791,388 shares of Class A Common Stock and 199,987,976 shares of Class C Common Stock, par value $0.0001 per share outstanding. The shares of Class A Common Stock shown as outstanding do not include 477,797 unvested restricted stock awards outstanding as of January 31, 2020.

Portions of the registrant’s definitive Proxy Statement for its 2020 annual meeting of shareholders, which will be filed with the Securities and Exchange Commission on Schedule 14A within 120 days after the end of 2019, will be incorporated by reference into Part III of this Form 10-K to the extent indicated therein upon such filing.

Table of Contents

໿

		Page
	Glossary	i
	Cautionary Statement Regarding Forward-Looking Statements	1
	PART I
Item 1.	Business	2
Item 1A.	Risk Factors	1310
Item 1B.	Unresolved Staff Comments	4510
Item 2.	Properties	4510
Item 3.	Legal Proceedings	5115
Item 4.	Mine Safety Disclosures	5218
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	5218
Item 6.	Selected Financial Data	5519
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	5619
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	8337
Item 8.	Financial Statements and Supplementary Data	8538
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~149~~96
Item 9A.	Controls and Procedures	~~149~~96
Item 9B.	Other Information	~~153~~98
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	~~153~~98
Item 11.	Executive Compensation	~~161~~98
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~184~~98
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~187~~98
Item 14.	Principal Accounting Fees and Services	~~195~~98
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	~~196~~99
Item 16.	Form 10-K Summary	~~199~~102
	Signatures	~~200~~103

Table of Contents

Index to Financial Statements

Glossary of Terms

The definitions and abbreviations set forth below apply to the indicated terms used throughout this filing.

Company Specific Terms -
2018 Predecessor Period -	The period from January 1, 2018 through February 8, 2018.
2024 Notes -	$500 million outstanding principal amount of senior unsecured notes of Alta Mesa bearing interest at 7.875%, payable semi-annually, maturing in December 2024.
2018 Successor Period -	The period from February 9, 2018 through December 31, 2018.
Alta Mesa -	Alta Mesa Holdings, LP. This entity conducts our Upstream activities.
2024 Notes -	$500 million outstanding principal amount of senior unsecured notes of Alta Mesa bearing interest at 7.875%, payable semi-annually, scheduled to mature in December 2024.
Additional Debtors -	The KFM Debtors and the SRII Debtors combined.
Alta Mesa -	Alta Mesa Holdings, LP, which conducts our Upstream activities.
Alta Mesa GP -	Alta Mesa Holdings GP, LLC, a majority owned subsidiary of SRII Opco, LP.
Alta Mesa RBL -	Alta Mesa Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, as amended. This credit agreement is a reserve based loan or RBL.
Alta Mesa Services -	A wholly owned subsidiary of Alta Mesa Holdings, LP.
AMH Debtors -	Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP.
AM Contributor -	High Mesa Holdings, LP, a partnership formed in connection with executing the Business Combination.
AMH PSA -	Amended & Restated Purchase and Sale Agreement by and among Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp., Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP, as Seller and BCE-Mach III LLC, as Buyer, and Alta Mesa Resources, Inc., dated January 17, 2020.
AMH Sale Transaction -	The expected sale by the AMH Debtors of substantially all of their assets to BCE-Mach III LLC pursuant to the AMH PSA.
AMR -	Alta Mesa Resources, Inc.
ARM -	ARM Energy Management, LLC, a company that markets our oil and gas production and provides services relating to our derivatives.
Bankruptcy Code -	Chapter 11 of the United States Bankruptcy Code.
Bankruptcy Court -	United States Bankruptcy Court for the Southern District of Texas.
BCE -	BCE-STACK Development LLC, a fund advised by Bayou City Management, LLC.
Business Combination -	The acquisition by Alta Mesa Resources, Inc. of controlling interests in Alta Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, and KFM Midstream, LLC.
Buyer -	BCE-Mach III LLC.
Debtors -	The Initial Debtors and Additional Debtors combined.
High Mesa -	High Mesa Holdings, LP, a partnership formed in connection with executing the Business Combination.
HMI -	High Mesa, Inc., the predecessor owner of Alta Mesa Holdings, LP.
KFM -	Kingfisher Midstream, LLC. This entity conducts our Midstream activities.
Initial Debtors -	Alta Mesa Resources, Inc., Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services, LP and Oklahoma Energy Acquisitions, LP.
KFM Contributor -	KFM Holdco, LLC.
KFM -	Kingfisher Midstream, LLC, which conducts our Midstream activities.
KFM Credit Facility -	Kingfisher Midstream, LLC amended and restated senior secured revolving credit facility with Wells Fargo Bank, National Association, as the administrative agent.
KFM Debtors -	Kingfisher Midstream, LLC, Kingfisher STACK Oil Pipeline, LLC, Oklahoma Produced Water Solutions, LLC and Cimarron Express Pipeline, LLC.
KFM PSA -	Amended and Restated Purchase and Sale Agreement by and among Kingfisher Midstream, LLC, Oklahoma Produced Water Solutions, LLC, Kingfisher STACK Oil Pipeline, LLC and Cimarron Express Pipeline, LLC, as Seller, and BCE-Mach III LLC, as Buyer, dated January 17, 2020.
KFM Sale Transaction -	The expected sale by the KFM Debtors of substantially all of their assets to BCE-Mach III LLC pursuant to the KFM PSA.
Midstream -	Reportable business segment representing our midstream activities.
Predecessor Periods -	The years ended December 31, 2017, 2016, 2015 and 2014 and the 2018 Predecessor Period.
PSAs -	The AMH PSA and KFM PSA combined.
Riverstone Contributor -	Riverstone VI Alta Mesa Holdings, L.P.
Successor Period -	The period from February 9, 2018 through December 31, 2018.
Sponsor -	Silver Run Sponsor II, LLC.
SRII Opco -	SRII Opco, LP is a subsidiary of Alta Mesa Resources, Inc. and direct owner of Alta Mesa Holdings, LP and Kingfisher Midstream, LLC.
Tax Receivable Agreement -	Tax Receivable Agreement dated as of February 9, 2018, among Alta Mesa Resources, Inc., SRII Opco, LP, Riverstone VI Alta Mesa Holdings, L.P., and High Mesa Holdings LP.
Upstream -	Reportable business segment representing our exploration and production activities.
Oil, Gas and Other Terms -
3D Seismic -	(Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional seismic data.
Basin -	A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
bbl -	One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to describe volumes of crude oil, condensate or natural gas liquids.
bbld -	Barrels per day.
Bcf -	One billion cubic feet of natural gas.
Bcfe -	One billion cubic feet of natural gas equivalent with one barrel of oil converted to six thousand cubic feet of natural gas. The ratio of six thousand cubic feet of natural gas to one bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six thousand cubic feet of natural gas to one bbl of oil or natural gas liquids.

Table of Contents

Index to Financial Statements

PSU's -	Performance-based restricted stock units issued to employees under the Alta Mesa Resources, Inc. 2018 Long-Term Incentive Plan.
Riverstone Contributor -	Riverstone VI Alta Mesa Holdings, L.P.
Sale Transactions -	The AMH Sale Transaction and KFM Sale Transaction combined.
Sponsor -	Silver Run Sponsor II, LLC.
SRII Debtors -	SRII Opco, LP and SRII Opco GP, LLC.
SRII Opco -	SRII Opco, LP is a subsidiary of Alta Mesa Resources, Inc. and direct owner of Alta Mesa Holdings, LP and Kingfisher Midstream, LLC.
Tax Receivable Agreement -	Tax Receivable Agreement dated as of February 9, 2018, among Alta Mesa Resources, Inc., SRII Opco, LP, Riverstone VI Alta Mesa Holdings, L.P., and High Mesa Holdings LP.
Upstream -	Reportable business segment representing our exploration and production activities.
Wind down -	This represents the post-sale activities to conclude the affairs of the Company, including final settlement of the Company's estate.
Oil, Gas and Other Terms -
3D Seismic -	(Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional seismic data.
Basin -	A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
bbl -	One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to describe volumes of crude oil, condensate or natural gas liquids.
bbld -	Barrels per day.
Bcf -	One billion cubic feet of natural gas.
Bcfe -	One billion cubic feet of natural gas equivalent with one barrel of oil converted to six thousand cubic feet of natural gas. The ratio of six thousand cubic feet of natural gas to one bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six thousand cubic feet of natural gas to one bbl of oil or natural gas liquids.
Boe -	One barrel of oil equivalent is determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one bbl of oil or natural gas liquids is commonly used in our business and represents the approximate ratio of energy content between natural gas and oil, and does not represent the price equivalency of natural gas to oil or natural gas liquids.
Boed -	One Boe per day.
Btu -	(British Thermal Unit) The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Btu or British Thermal Unit -	The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion -	The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil.
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.
Cryogenic -	The process of using extreme cold to separate NGLs from the natural gas stream.
DD&A -	Depreciation, depletion and amortization.
Developed acreage -	The number of acres that are allocated or assignable to productive wells or wells capable of production.
Developed reserves -	Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the related equipment is relatively minor compared to the cost of a new well.
Development costs -	Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas.
Development well -	A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential -	An adjustment to the market reference price of oil, natural gas or natural gas liquids from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole -	A well found to be incapable of producing hydrocarbons in commercial quantities.
Dry hole costs -	Costs incurred in drilling an unsuccessful exploratory well, including plugging and abandonment costs.
Dth -	A dekatherm is a unit of energy used primarily to measure natural gas and is equal to 1,000,000 Btu.
EBITDA -	Earnings before interest, taxes, depreciation, depletion and amortization.
EBITDAX -	Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses.
Enhanced recovery -	The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.
Exploitation -	A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Exploratory well -	A well drilled to find a new field or to find a new reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.
Field -	An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Formation -	A layer of rock which has distinct characteristics that differs from adjacent rock.
Fracing, fracture stimulation technology, hydraulic fracturing -	A well stimulation technique to improve a well’s production by pumping a mixture of fluids into the formation to create hydraulic fractures which intersect existing natural fractures. As part of this technique, sand or other material may also be injected to keep the hydraulic fracture open, so that fluids or natural gases may more easily flow through the formation.
Gross acres or gross wells -	The total acres or wells in which a working interest is owned.

Table of Contents

Index to Financial Statements

Held by production - Acreage covered by mineral leases that perpetuates a company’s right to operate a property usually requiring production to be maintained at a minimum economic quantity of production. Horizontal drilling - A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval. Lease operating expenses - The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a well. Such expenses include labor, supplies, repairs, utilities, environmental and safety, maintenance, allocated overhead costs, severance taxes, insurance and other expenses incidental to production, but excluding lease acquisition, drilling or completion expenses. Mbbl - One thousand barrels of crude oil, condensate, natural gas liquids, or produced water. Mbbld - One thousand barrels per day. MBoe - One thousand Boe. MBoed - One thousand Boe per day. Mcf - One thousand cubic feet of natural gas. Mcfd - One thousand cubic feet per day. Mcfe - One thousand cubic feet equivalent determined using the ratio of one barrel of oil, condensate or natural gas liquids to six Mcf of natural gas. Mcfed - Mcfe per day. MMBoe - One million boe. MMBtu - One million British thermal units. MMBtud - One million British thermal units per day. MMcf - One million cubic feet of natural gas. MMcfd - One million cubic feet per day. MMBbl - One million barrels of crude oil, condensate or natural gas liquids. Net acres - The total acres a working interest owner has attributable to a particular number of acres, or a specified tract. Net production - Portion of production owned by us after production attributable to royalty and other owners. Net revenue interest - A working interest owner’s working interest in production after deducting royalty, overriding royalty, production payments and net profits interests. NGLs ornatural gas liquids - Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline. NYMEX - The New York Mercantile Exchange. P&A - (Plug and Abandonment) is the permanent dismantlement and removal of production equipment and facilities from service at the end of an asset’s economic life. PDNP - Proved developed non-producing reserves. PDP - Proved developed producing reserves. Produced water - Byproduct associated with the production of crude oil and natural gas that often contains a number of dissolved solids and other materials found in oil and gas reservoirs. Productive well - A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. Proved developed reserves - Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and can be expected to be recovered through extraction technology installed and operational at the time of the reserve estimate. Proved properties - Properties with proved reserves. Proved reserves - Quantities of oil and natural gas, which can be estimated with reasonable certainty to be economically producible from known reservoirs, and under existing economic conditions, operating methods and government regulations. Proved undeveloped reserves ("PUD") - Reserves that are expected to be recovered from new wells, or from existing wellbores where a relatively major expenditure is required to make the well producible.



Differential -	An adjustment to the market reference price of oil, natural gas or natural gas liquids from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole -	A well found to be incapable of producing hydrocarbons in commercial quantities.
Dry hole costs -	Costs incurred in drilling an unsuccessful exploratory well, including plugging and abandonment costs.
Dth -	A dekatherm is a unit of energy used primarily to measure natural gas and is equal to 1,000,000 Btu.
Dthd -	1,000,000 Btu per day.
EBITDA -	Earnings before interest, taxes, depreciation, depletion and amortization.
EBITDAX -	Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses.
Exploratory well -	A well drilled to find a new field or to find a new reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.
Field -	An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Formation -	A layer of rock which has distinct characteristics that differs from adjacent rock.
Fracing, fracture stimulation technology, hydraulic fracturing -	A well stimulation technique to improve a well’s production by pumping a mixture of fluids into the formation to create hydraulic fractures which intersect existing natural fractures. As part of this technique, sand or other material may also be injected to keep the hydraulic fracture open, so that fluids or natural gases may more easily flow through the formation.
Gross acres or gross wells -	The total acres or wells in which a working interest is owned.
Held by production -	Acreage covered by mineral leases that perpetuates a company’s right to operate a property usually requiring production to be maintained at a minimum economic quantity of production.
Horizontal drilling -	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval.
Lease operating expenses -	The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a well. Such expenses include labor, supplies, repairs, utilities, environmental and safety, maintenance, allocated overhead costs, severance taxes, insurance and other expenses incidental to production, but excluding lease acquisition, drilling or completion expenses.
Mbbl -	One thousand barrels of crude oil, condensate, natural gas liquids, or produced water.
Mbbld -	One thousand barrels per day.
MBoe -	One thousand Boe.
MBoed -	One thousand Boe per day.
Mcf -	One thousand cubic feet of natural gas.
Mcfd -	One thousand cubic feet per day.
Mcfe -	One thousand cubic feet equivalent determined using the ratio of one barrel of oil, condensate or natural gas liquids to six Mcf of natural gas.
Mcfed -	Mcfe per day.
MMBoe -	One million boe.
MMBtu -	One million British thermal units.
MMBtud -	One million British thermal units per day.
MMcf -	One million cubic feet of natural gas.
MMcfd -	One million cubic feet per day.
MMcfe -	Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMcfed -	MMcfe per day.
MMBbl -	One million barrels of crude oil, condensate or natural gas liquids.

iii

Table of Contents

Index to Financial Statements

PV-10 -	When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenue. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
Net acres -	The total acres a working interest owner has attributable to a particular number of acres, or a specified tract.
Net production -	Portion of production owned by us after production attributable to royalty and other owners.
Net revenue interest -	A working interest owner’s working interest in production after deducting royalty, overriding royalty, production payments and net profits interests.
NGLs ornatural gas liquids -	Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline.
Non-operated working interests -	The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement.
NYMEX -	The New York Mercantile Exchange.
P&A -	Plug and Abandonment (P&A) is the permanent dismantlement and removal of production equipment and facilities from service at the end of an asset’s economic life.
PDNP -	Proved developed non-producing reserves.
PDP -	Proved developed producing reserves.
Produced water -	Byproduct associated with the production of crude oil and natural gas that often contains a number of dissolved solids and other materials found in oil and gas reservoirs.
Productive well -	A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Proved developed reserves -	Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and can be expected to be recovered through extraction technology installed and operational at the time of the reserve estimate.
Proved properties -	Properties with proved reserves.
Proved reserves -	Quantities of oil and natural gas, which can be estimated with reasonable certainty to be economically producible from known reservoirs, and under existing economic conditions, operating methods and government regulations.
Proved undeveloped reserves ("PUD") -	Reserves that are expected to be recovered from new wells, or from existing wellbores where a relatively major expenditure is required to make the well producible.
PV-10 -	The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenue. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
Realized price -	The cash market price less all expected quality, transportation and demand adjustments.
Recompletion -	The process of treating an existing wellbore in an attempt to establish or increase existing production.
Reserves -	Estimated remaining quantities of oil and natural gas anticipated to be economically producible from known accumulations.
Reservoir -	A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Resources -	Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable.
Royalty -	An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage.
SEC -	United States Securities and Exchange Commission.
Service well -	A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, produced water disposal, water supply for injection, observation, or injection for in-situ combustion.
Spacing -	The distance between wells producing from the same reservoir. Spacing in horizontal development plays is often expressed in terms of feet, e.g., 1000 foot spacing, and is often established by regulatory agencies.
STACK -	An oilfield in the eastern portion of the Anadarko Basin; STACK is an acronym describing both its location—Sooner Trend Anadarko Basin Canadian and Kingfisher County—and the multiple, stacked productive formations present in the area.
Standardized Measure -	Standardized measure is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the U.S. Securities and Exchange Commission, without giving effect to non-property related expenses such as certain general and administrative expenses, interest expense and depletion, discounted using an annual discount rate of 10%.
Stratigraphic test well -	A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
Success rate -	The percentage of wells drilled which produce hydrocarbons in commercial quantities.
Undeveloped acreage -	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Unit -	The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation. Also, the area covered by a unitization agreement.
Unproved properties -	Properties with no proved reserves.
VWAP -	Volume weighted average price.
Waterflood -	The injection of water into an oil reservoir to “sweep” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically, an enhanced recovery process.

Table of Contents

Index to Financial Statements

Working interest - The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs. Workover - Operations on a producing well to restore or increase production.



STACK -	An oilfield in the eastern portion of the Anadarko Basin; STACK is an acronym describing both its location—Sooner Trend Anadarko Basin Canadian and Kingfisher County—and the multiple, stacked productive formations present in the area.
Standardized Measure -	Standardized measure is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the U.S. Securities and Exchange Commission, without giving effect to non-property related expenses such as certain general and administrative expenses, interest expense and depletion, discounted using an annual discount rate of 10%.
Stratigraphic test well -	A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
Undeveloped acreage -	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Unit -	The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation. Also, the area covered by a unitization agreement.
Unproved properties -	Properties with no proved reserves.
VWAP -	Volume weighted average price.
Wellbore -	The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called a well or borehole.
Working interest -	The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs.
Workover -	Operations on a producing well to restore or increase production.

Table of Contents

Index to Financial Statements

Cautionary Statement Regarding Forward-Looking Statements

The information in this Annual Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Annual Report, regarding our strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could”, “should”, “will”, “plan”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project”, the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in Part I, Item 1A of this Annual Report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about:


•	the expected closing of the Sale Transactions;


•	our expectations of outcomes in our bankruptcy proceedings;


•	our ability to fulfill the transition services agreement with the buyer of our assets;


•	our ability to continue as a going concern;

• our ability to comply with, ~~or amend~~ the ~~terms~~requirements ~~of, the covenants and restrictions~~ imposed by our ~~debt~~bankruptcy ~~agreements, including our ability to repay amounts borrowed under the Alta Mesa RBL that exceed the current borrowing base~~process;


•	our business strategy;


•	our reserve quantities and the present value of our reserves;


•	our exploration and drilling prospects, inventories, projects and programs;


•	our drilling, completion and production technology;


•	our ability to replace the reserves we produce through drilling and through acquisitions;


•	future oil and gas prices;


•	the supply and demand for our production and our midstream services;


•	the timing and amount of our future production;

• our hedging strategy and expected results;


•	competition and government regulation;


•	our ability to obtain permits and governmental approvals;

• expected or anticipated changes in the Oklahoma forced pooling system;

• pending legal and environmental matters;


•	our future drilling plans, spacing plans and development pace;


•	our marketing of our production;

• our leasehold or business acquisitions;

• our costs of developing our properties;

• the sufficiency of our liquidity position to ensure financial flexibility and fund our operations and capital expenditures;


•	our access to capital, including constraints from the cost and availability of debt and equity financing;

• ~~our~~operating ~~ability~~hazards and other risks incidental to ~~hire~~transporting, ~~train~~storing, orgathering ~~retain~~and ~~qualified~~processing ~~personnel~~natural gas, NGLs, crude oil and midstream products;

• general economic conditions;

• operating hazards and other risks incidental to transporting, storing, gathering and processing natural gas, natural gas liquids, crude oil and midstream products;


•	our future operating results, including production levels, initial production rates and yields in our type curve areas;


•	the costs, terms and availability of midstream services;


•	pending legal and environmental matters;


•	our ability to retain qualified personnel during our wind-down period and the sufficiency of resources to conduct the wind down;


•	general economic conditions;


•	our plans, objectives, expectations and intentions contained in this Annual Report that are not historical; and


•	our ability to collect receivables from High Mesa, Inc. and its subsidiaries.

We caution you that any forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control~~, incident to the exploration for and development, production, gathering and sale of oil, natural gas and natural gas liquids~~. Some factors that could cause actual results to differ materially from those expressed or implied by these forward looking statements include, but are not limited to, the Buyer’s ability ofand willingness to close the ~~combined~~Sale ~~company~~Transactions, toorders ~~realize~~by the ~~anticipated~~Bankruptcy ~~benefits~~Court ofthat impact the ~~Business~~ability ~~Combination~~to fund and conduct our operations, liabilities resulting from litigation or the SEC investigation, commodity price volatility, global economic conditions, including supply and demand levels for oil, gas and NGLs, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, liabilities resulting from litigation or the SEC investigation, difficulty in obtaining necessary approvals and permits, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, cyber-attacks, title defects, limited control over non-operated properties, our ability to satisfy future cash obligations, restrictions in our debt agreements, and the other risks with the wind down of our operations.

Table of Contents

Index to Financial Statements

~~cash~~natural ~~flow,~~gas ~~lack~~and ofNGLs ~~access~~that towill ~~capital,~~be ~~our~~ultimately ~~ability~~produced, todrilling ~~satisfy~~and ~~future~~operating ~~cash~~expenses, ~~obligations~~capital expenditures, ~~restrictions~~the ineffect ~~our~~of ~~debt~~government ~~agreements~~regulation, ~~the~~taxes ~~timing~~and availability of ~~development~~funds. Future ~~expenditures,~~prices ~~managing~~received ~~our~~for ~~growth~~production and ~~integration~~costs ofmay ~~acquisitions~~vary, ~~cyber-attacks~~perhaps significantly, ~~failure~~from tothe ~~realize~~prices ~~expected~~and ~~value~~costs ~~creation~~assumed ~~from~~for ~~property~~purposes ~~acquisitions,~~of ~~title~~these ~~defects~~estimates. In addition, ~~limited~~the ~~control~~results ~~over~~of ~~non-operated properties~~drilling, testing and ~~the~~production ~~other~~activities ~~risks~~may ~~described~~justify ~~under~~revisions ~~“Item~~of ~~1A.~~estimates ~~Risk~~that ~~Factors”~~were inmade ~~this Annual Report~~previously.

Estimating quantities of oil, natural gas and NGL reserves is complex and inexact. The process relies on interpretations of geologic, geophysical, engineering and production data. The extent, quality, reliability and interpretation of these data can vary. The process also requires a number of economic assumptions, such as oil, natural gas and NGL prices, the relative mix of oil, natural gas and NGLs that will be ultimately produced, drilling and operating expenses, capital expenditures, the effect of government regulation, taxes and availability of funds. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances occurring after the date of this Annual Report.

PART I

Item 1. Business

Overview

Alta Mesa Resources, Inc. (“AMR”), together with its consolidated subsidiaries (“we”, “us”, “our” or “the Company”), is an independent exploration and production company focused on the ~~acquisition,~~ development, ~~exploration and exploitation~~ of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. ~~We also operate in the Midstream segment through~~ Kingfisher Midstream, LLC (“KFM”) conducts our Midstream operations. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that ~~generate~~generates revenue primarily through long-term, fee-based contracts. ~~The KFM assets are integral to our Upstream operations, which we conduct in the same region, and they are strategically positioned to provide similar services to other producers in the area.~~ Our principal offices are at 15021 Katy Freeway, Suite 400, Houston, Texas 77094 and our main phone number is (281) 530-0991.

We were originally incorporated in Delaware in November 2016 as a special purpose acquisition company under the name Silver Run Acquisition Corporation II. On ~~for~~March 29, 2017, we consummated our initial public offering (“IPO”). Proceeds from the ~~purpose~~IPO and a private sale of ~~effecting~~warrants were placed in a ~~merger~~trust account and were used on February 9, ~~capital~~2018, ~~stock~~to ~~exchange~~acquire the interests in Alta Mesa, ~~asset~~Alta ~~acquisition~~Mesa Holdings GP, ~~stock~~LLC ~~purchase~~(“Alta Mesa GP”) and KFM through a newly formed subsidiary, ~~reorganization~~SRII orOpco, ~~similar~~LP ~~business~~(“SRII ~~combination~~Opco”) ~~involving~~in a transaction referred to as the ~~Company~~“Business ~~and~~Combination” ~~one~~at orwhich ~~more~~time ~~businesses~~we changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.”.

InOn ~~connection~~September ~~with~~11, ~~the~~2019, ~~closing~~AMR, Alta Mesa and all of its subsidiaries (the ~~Business~~“AMH ~~Combination~~Debtors” ~~discussed~~and ~~below~~together with AMR, the ~~Company~~“Initial ~~changed~~Debtors”) ~~its~~filed ~~name~~voluntary ~~from~~petitions (“~~Silver~~Initial ~~Run~~Bankruptcy ~~Acquisition~~Petitions”) ~~Corporation~~for ~~II”~~relief tounder Chapter 11 of the U.S. Bankruptcy Code (“~~Alta~~Bankruptcy ~~Mesa~~Code”) ~~Resources,~~in ~~Inc~~the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).

~~Beginning~~On inJanuary ~~the~~12, ~~1990’s~~2020, ~~our~~KFM ~~predecessor~~and ~~operations~~all ~~were~~of ~~focused~~its onsubsidiaries ~~vertical wells~~(collectively, ~~waterfloods and analyzing~~ the ~~commercial~~“KFM ~~productivity~~Debtors”) offiled ~~the~~voluntary ~~stacked~~petitions ~~formations~~(“ onKFM ~~our~~Bankruptcy ~~acreage. Since~~Petitions”) ~~2012,~~for ~~our~~relief ~~activities~~under ~~have~~the ~~become~~Bankruptcy ~~primarily~~Code. On ~~directed~~January at13, ~~the~~2020, ~~horizontal~~SRII ~~development~~Opco ofGP, anLLC ~~oil~~ and ~~liquids-rich~~SRII ~~resource~~Opco ~~play~~(collectively, in the ~~STACK. The~~“SRII ~~STACK~~Debtors” isand, atogether ~~prolific hydrocarbon system~~ with ~~high~~the ~~oil~~KFM ~~and~~Debtors, ~~liquids-rich~~the ~~natural~~“Additional ~~gas~~Debtors”) ~~content,~~filed ~~with~~voluntary ~~potential~~petitions ~~for~~(“SRII ~~multiple~~Bankruptcy ~~horizontal~~Petitions ~~target horizons~~and, ~~extensive~~together ~~production~~with ~~history~~the ~~and~~KFM ~~high~~Bankruptcy ~~drilling~~Petitions, ~~success~~the ~~rates.~~“Additional WeBankruptcy ~~generally~~Petitions”) ~~maintain~~for ~~operational~~relief ~~control~~under of the ~~majority~~Bankruptcy ofCode. The ~~our~~Additional ~~properties,~~Debtors’ ~~either~~Chapter ~~through~~11 ~~directly~~cases ~~operating~~are ~~them~~being orjointly ~~through~~administered ~~operating~~with ~~arrangements~~the ~~with~~Initial ~~other~~Debtors’ ~~interest~~Chapter ~~owners.~~11 cases.

AsThe ofInitial ~~December~~and ~~31,~~Additional ~~2018,~~Debtors weoperate ~~have~~their ~~assembled~~businesses aas ~~highly contiguous position of 140,400 net acres~~ “debtors-in ~~the up~~-~~dip,~~possession” ~~naturally-fractured~~under ~~oil~~the ~~portion~~jurisdiction of the ~~STACK,~~Bankruptcy ~~primarily~~Court ~~in eastern Kingfisher~~ and ~~southeastern Major Counties~~ in ~~Oklahoma.~~accordance ~~Our~~with ~~drilling~~the ~~locations~~applicable ~~primarily~~provisions ~~target~~of the ~~Osage,~~Bankruptcy ~~Meramec and Oswego formations~~Code. ~~After~~ ~~the Business Combination, we conducted~~

On December 31, 2019, the Initial Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “AMH PSA”) with BCE-Mach III LLC (the “Buyer”) pursuant to which the AMH Debtors agreed to sell to the Buyer substantially all of our upstream assets for an unadjusted purchase price of $232.0 million in cash, subject to customary purchase price adjustments (such transaction, the “AMH Sale Transaction”). On December 31, 2019, the KFM Debtors entered into a Purchase and Sale Agreement (as amended and restated in January 2020, the “KFM PSA” and, together with the AMH PSA, the “PSAs”) with the Buyer pursuant to which the KFM Debtors agreed to sell to the Buyer substantially all of our midstream assets for an unadjusted purchase price of $88.0 million in cash, subject to customary purchase price adjustments (such transaction, the “KFM Sale Transaction” and, together with the AMH Sale Transaction, the “Sale Transactions”).

Table of Contents

Index to Financial Statements

~~development~~The ~~activities~~Sale ~~using~~Transactions aare ~~spacing~~expected ~~array of 6~~ to 10close ~~wells~~no ~~per~~later ~~section~~than ~~and~~mid-April ~~running up to 9 rigs at the peak activity level. In late 2018~~2020, ~~our~~after ~~production~~which ~~across~~we ~~the~~will ~~acreage~~no ~~evidenced~~longer ~~that~~own ~~the~~any ~~well~~operating ~~spacing~~assets. Following ~~was not delivering~~ the ~~well level production that we~~ expected. ~~During January 2019~~sale, we ~~suspended~~intend ~~our development program~~ to ~~allow~~provide ~~our~~certain ~~new~~transition ~~management~~services ~~team~~ to ~~conduct~~the aBuyer ~~full~~for ~~operational and economic review. We restarted our development program in March 2019 with~~ a ~~less~~limited ~~dense~~period ~~spacing pattern~~ of uptime toand ~~five~~expect ~~wells per section. In addition, we have worked~~ to ~~improve~~wind down our ~~economic~~remaining ~~returns~~business byduring ~~reducing well costs, general and administrative expense and other operating expense. We have operated 2 rigs since restarting~~ the ~~program,~~first ~~however~~half ~~following the redetermination~~ of ~~the borrowing base of the Alta Mesa RBL in August~~2020, wewhich ~~have~~will ~~decided~~result ~~to operate 1 rig starting~~ in ~~September. We~~the ~~will~~dissolution ~~continue~~of toAMR ~~evaluate~~and ~~how~~its ~~much, if any, development is appropriate going forward~~subsidiaries.

~~Organizational~~In ~~Structure~~March 2020, AMR, the AMH Debtors and the SRII Debtors expect to file a Chapter 11 plan (collectively, the “AMR Plan”). The AMR Plan will generally provide for the distribution of the proceeds of the AMH Sale Transaction to AMH’s creditors and transfer any remaining assets of the Initial Debtors and SRII Opco Debtors into a liquidating trust to administer and monetize such assets and to reconcile creditor claims against such debtors for the benefit of their respective creditors. Pursuant to the AMR Plan, all outstanding shares of class A common stock and class C common stock in the Company are expected to be canceled.

The ~~following~~AMR ~~diagram~~Plan ~~illustrates~~will ~~our~~be ~~ownership~~subject ~~structure~~to asapproval by the Bankruptcy Court and the Initial Debtors and the SRII Debtors are expected to solicit votes on the AMR Plan from certain of ~~December~~their 31creditors entitled to vote thereon pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the AMR Plan in April 2020. To the extent that the AMR Plan is confirmed by the Bankruptcy Court, ~~2018~~AMR expects the AMR Plan to become effective and be consummated shortly thereafter.

~~Business~~In ~~Combination~~March 2020, the KFM Debtors filed a Chapter 11 plan (the “KFM Plan”). The KFM Plan will generally provide for the (i) distribution of the proceeds of the KFM Sale Transaction to creditors, (ii) liquidation of any remaining assets of the KFM Debtors, and (iii) orderly wind-down of the KFM Debtors’ estates. Under the KFM Plan, the KFM Debtors will appoint a plan administrator who will, among other things, oversee the wind-down of the KFM Debtors and implement all provisions of the KFM Plan, including controlling and effectuating claims reconciliation.

AsThe ~~described~~KFM ~~further~~Plan inis ~~Item~~subject 8to ofapproval ~~this~~by ~~Annual~~the ~~Report,~~Bankruptcy ~~certain~~Court ~~transactions~~and ~~were~~the ~~consummated~~KFM onDebtors ~~February~~are 9,expected ~~2018, that~~to ~~resulted~~solicit invotes ~~our~~on ~~acquisition~~the ofKFM ~~interests~~Plan infrom ~~Alta~~certain ~~Mesa,~~of ~~Alta~~the ~~Mesa~~KFM ~~Holdings~~Debtors’ ~~GP,~~creditors ~~LLC~~pursuant ~~(“Alta~~to ~~Mesa~~the ~~GP”)~~requirements ~~and~~of ~~KFM~~the ~~through~~Bankruptcy aCode. We ~~newly~~expect ~~formed~~the ~~subsidiary,~~Bankruptcy ~~SRII~~Court ~~Opco,~~to LPhold ~~(“SRII~~a ~~Opco”).~~hearing ~~These~~to ~~transactions~~consider ~~are~~confirmation ~~referred~~of tothe asKFM ~~the~~Plan ~~“Business~~in ~~Combination~~April 2020.” ~~Prior~~To tothe extent that the ~~closing~~KFM ofPlan is confirmed by the ~~Business~~Bankruptcy ~~Combination~~Court, ~~Alta~~KFM ~~Mesa~~expects ~~was~~the ~~controlled~~KFM byPlan ~~High~~to ~~Mesa,~~become ~~Inc.~~effective ~~(“HMI”)~~and be consummated shortly thereafter.

~~During~~Our ~~the~~Class ~~fourth~~A ~~quarter~~Common ofStock ~~2017,~~and ~~Alta~~public ~~Mesa~~warrants ~~sold~~to ~~certain~~purchase ofClass ~~its~~A ~~non-STACK~~Common ~~oil~~Stock, ~~and~~sold ~~gas~~as ~~assets~~part ~~and~~of ~~liabilities. Immediately~~the ~~prior~~shares toissued in the ~~closing~~IPO, ofwere ~~the~~initially ~~Business~~traded ~~Combination,~~on ~~Alta~~the ~~Mesa~~NASDAQ ~~distributed~~Capital ~~its~~Market ~~remaining~~(“NASDAQ”), ~~non-STACK~~but ~~oil~~due ~~and~~to ~~gas~~our ~~assets~~failure ~~and~~to ~~liabilities~~continue to ~~High~~meet ~~Mesa~~the ~~Holdings,~~NASDAQ’s LPlisting ~~(the~~requirements, ~~“AM~~trading ~~Contributor”),~~in ~~such~~our ~~that~~stock ~~Alta~~and ~~Mesa’s~~public ~~only~~warrants ~~remaining~~was ~~oil~~suspended ~~and~~in ~~gas~~September ~~assets~~2019, and ~~liabilities~~are ~~were~~now ~~located~~traded inover the ~~STACK. As~~counter ~~described~~on ~~elsewhere,~~ the AMOTC ~~Contributor~~Pink ~~owes~~Marketplace usunder athe ~~substantial~~symbols ~~sum~~“AMRQQ” ~~for~~and ~~amounts~~“AMRWQ”, ~~arising~~respectively. In ~~before~~February ~~and~~2020, ~~after~~we ~~the~~filed ~~Business~~forms ~~Combination,~~with ~~and~~the itSecurities ~~has~~and ~~indemnified~~Exchange usCommission ~~for~~to ~~liabilities~~deregister ~~arising~~our ~~from~~Class ~~non-STACK~~A ~~oil~~Common Stock and ~~gas~~warrants ~~assets. We~~under ~~believe~~Section ~~there~~12(g) isof ~~substantial~~the ~~doubt~~Securities ~~about~~Exchange ~~its~~Act ~~ability~~of to1934, ~~make~~as ~~payment~~amended, ~~and~~(the ~~honor~~“Exchange ~~its~~Act”) ~~indemnification. Information~~and ~~related~~suspend toour ~~Alta~~reporting ~~Mesa’s~~obligations ~~non-STACK~~under ~~oil~~Sections 13 and ~~gas~~15(d) ~~assets~~of ~~and~~the ~~liabilities~~Exchange ~~that~~Act. Accordingly, ~~were~~we ~~sold~~do ornot ~~distributed~~anticipate isfiling ~~disclosed~~any asadditional ~~discontinued~~current, ~~operations~~quarterly inor ~~Item~~annual 8reports ofwith ~~this~~the ~~Annual Report~~SEC.

~~Pursuant~~Going to the Business Combination, we recorded the acquired assets and liabilities at their estimated fair values and pushed those values down to the financial records of our respective subsidiaries. This resulted in our financial presentation being Concern

AMR’s only significant asset is its ownership of a partnership interest in SRII Opco. As such, we have no meaningful cash available to meet our obligations apart from cash held by our subsidiaries. As a result of the bankruptcy filings by us and all of our subsidiaries, as described above, cash held by Alta Mesa and KFM can only be used to satisfy their obligations to the extent authorized by the Bankruptcy Code or by order of the Bankruptcy Court. The bankruptcy filings by the Initial Debtors and the Additional Debtors (collectively, “the Debtors”) triggered defaults in the Alta Mesa RBL, the 2024 Notes and the KFM Credit Facility, limiting our future borrowing ability and making our outstanding obligations immediately due and payable, although the creditors are currently stayed from taking any actions as a result of such defaults. The Debtors are also subject to limitations imposed under Bankruptcy Court approved cash collateral orders requiring us to (i) adhere to an approved budget with an agreed-upon variance and (ii) meet certain milestones.

We expect to sell substantially all of our assets no later than mid-April 2020. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

Table of Contents

Index to Financial Statements

~~separated~~These ~~into~~factors, ~~two~~including ~~distinct~~historic ~~periods~~recurring -operating ~~the~~losses, ~~period~~raise ~~before~~substantial ~~the~~doubt ~~Business~~about ~~Combination~~our onability ~~February~~to 9,continue ~~2018~~as ~~(“Predecessor”)~~a ~~and~~going ~~the period after the Business Combination (“Successor”)~~concern.

~~Going~~Organizational ~~Concern~~Structure

~~Our~~The ~~present~~following ~~level~~diagram ofillustrates ~~indebtedness and the current commodity price environment present challenges to~~ our ~~ability~~ownership tostructure comply with the covenants in the agreements governing our indebtedness. As a result of the decrease in our forecasted production levels compared to the forecasts at the time of the Business Combination and pressures created by lower commodity prices, in the absence of one or more deleveraging transactions, we do not anticipate maintaining compliance with the consolidated total leverage ratio covenant in the Alta Mesa RBL as ~~early as the measurement date~~ of September 30, 2019. In addition, we have been substantially fully utilized under the Alta Mesa RBL since April 2019 and have no meaningful remaining capital availability. Our lenders exercised their right to conduct an optional redetermination ahead of the regularly scheduled redetermination in October 2019 and have established a new borrowing base of $200.0 million, effective AugustDecember 1331, 2019. As provided under the Alta Mesa RBL, we have elected to repay the excess utilization in 5 equal monthly installments of $32.5 million, the first of which will be due in September 2019. If we are unable to make these deficiency payments, we would be in default under the Alta Mesa RBL. Our Board and its financial advisors are evaluating the available financial alternatives, including seeking amendments or waivers to the covenants or other provisions of our indebtedness to address our capital structure including raising new capital from the private or public markets or taking other actions either in court or out of court. If we are unable to reach an agreement with our lenders or find acceptable alternative financing, it may lead to an event of default under our debt agreements. If following an event of default, the Alta Mesa RBL lenders were to accelerate repayment, it may result in an event of default and an acceleration of the 2024 Notes. We have concluded that these circumstances create substantial doubt regarding our ability to continue as a going concern.

IfBusiness an agreement is reached with our creditors and we pursue a restructuring, it may be necessary for us, or our subsidiaries, to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in order to implement the agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court. We may also conclude it is necessary to initiate Chapter 11 proceedings to implement a restructuring of our obligations even if we are otherwise unable to reach an agreement with our creditors. If a plan of reorganization is implemented in a bankruptcy proceeding, it is possible that holders of claims and interests with respect to, or rights to acquire, our equity securities would be entitled to little or no recovery, and those claims and interests may be canceled for little or no consideration. If that were to occur, we anticipate that all or substantially all of the value of all investments in our equity securities would be lost and that our equity holders would lose all or substantially all of their investment. It is also possible that our stakeholders, including our secured and unsecured creditors, will receive substantially less than the amount of their claims. For a more detailed discussion, please read the Risk Factors in Item 1A.Combination

~~Sale~~As described further in Item 8 of ~~Produced~~this ~~Water~~Annual ~~Assets~~Report, the Business Combination was consummated on February 9, 2018, that resulted in our acquisition of interests in Alta Mesa, Alta Mesa GP and KFM through a newly formed subsidiary, SRII Opco. Prior to the Business Combination, Alta Mesa was controlled by High Mesa, Inc. (“HMI”).

InImmediately ~~November~~prior ~~2018~~to the closing of the Business Combination, Alta Mesa ~~sold~~distributed ~~substantially~~its ~~all~~non-STACK ofoil ~~its~~and ~~produced~~gas ~~water~~ assets, ~~consisting~~and ofliabilities ~~produced~~to ~~water~~High ~~gathering~~Mesa ~~pipelines~~Holdings, ~~facilities,~~LP ~~disposal~~(“High ~~wells~~Mesa”), ~~surface~~such ~~leases~~that Alta Mesa’s only remaining oil and ~~easements,~~gas toassets aand ~~subsidiary~~liabilities ofwere ~~KFM~~located ~~for~~in ~~approximately~~the ~~$99~~STACK. As ~~million~~described elsewhere, ~~including~~High ~~approximately~~Mesa ~~$90~~owes ~~million~~us ina ~~cash~~substantial atsum ~~closing~~for ~~and~~amounts $9arising ~~million~~before ofand ~~purchase~~after ~~price~~the ~~adjustments,~~Business ~~which~~Combination, inand ~~total,~~it ~~approximated~~had ~~the~~indemnified ~~net~~us ~~book~~for ~~value~~liabilities ofarising ~~the~~from ~~produced~~non-STACK ~~water~~oil and gas assets. We ~~Because~~believe ~~Alta~~there ~~Mesa~~is ~~and~~substantial ~~KFM~~doubt ~~are~~about ~~each~~its ~~owned~~ability byto ~~SRII~~make ~~Opco,~~payment ~~the~~and ~~transaction~~honor ~~was~~its ~~accounted~~indemnification ~~for~~given asHMI’s afiling ~~transfer~~for ofbankruptcy ~~assets~~protection ~~among~~in ~~entities~~January ~~under~~2020. Information ~~common~~related ~~control~~to ~~and~~Alta ~~the~~Mesa’s ~~purchase~~non-STACK ~~was~~oil ~~recorded~~and atgas ~~book~~assets ~~value~~and byliabilities ~~KFM. In~~that ~~conjunction~~were ~~with~~sold ~~the~~or ~~sale,~~distributed ~~Alta~~is ~~Mesa~~disclosed ~~entered~~as ~~into~~discontinued aoperations ~~new~~in ~~15-year~~Item ~~produced~~8 ~~water~~of ~~agreement~~this ~~with~~Annual ~~KFM~~Report.

~~Principal~~Pursuant ~~Products~~to the Business Combination, ~~Markets~~we recorded the acquired assets and ~~Customers~~liabilities at their estimated fair values and pushed those values down to the financial records of our respective subsidiaries. This resulted in our financial presentation being separated into two distinct periods - the period before the Business Combination on February 9, 2018 (“Predecessor”) and the period after the Business Combination (“Successor”).

Our Upstream segment sells our production to customers generally at prevailing spot prices in effect at the time of the sale. Our Midstream segment derives its revenue from fees assessed for gathering and processing natural gas, gathering and transporting oil, the sale of processed residue gas and NGLs and produced water gathering and disposal services. Natural gas is processed on behalf of the producer and the resulting gas, condensate and NGLs are sold at market prices. We remit to the producer an agreed-upon price from the resulting sales, which is treated as product expense. Collateral or other security is generally not required with regard to our trade receivables.

Table of Contents

Index to Financial Statements

~~Much~~Principal ~~of our oil and gas production in 2018~~Products, ~~including~~Markets ~~certain processed gas~~ and NGLs, was sold through a marketing agreement with ARM Energy Management, LLC (“ARM”), who marketed and sold our oil and gas production and processed products under short-term contracts, generally with month-to-month pricing based on published indices, adjusted for transportation, location and quality. ARM generally remitted monthly collections of these sales to us, net of its fee. For the Successor Period, ARM marketed $336.2 million, or 71% of our total operating revenue for the period. Customers

~~Effective~~Our asUpstream ofsegment ~~June~~sells 1,our ~~2019~~production of oil, wenatural ~~have~~gas ~~terminated~~and ~~our~~NGLs ~~oil~~to customers generally at prevailing spot prices in effect at the time of the sale. Our Midstream segment derives its revenue from fees assessed for gathering and ~~NGL~~processing ~~marketing~~natural ~~agreement~~gas, ~~with~~gathering ~~ARM~~and transporting oil, the sale of processed residue gas and ~~will~~NGLs ~~market~~and ~~such~~produced ~~products~~water ~~internally~~gathering and disposal services. WeNatural ~~have~~gas ~~extended~~is ~~the~~processed ~~term~~on behalf of ~~our~~the producer and the resulting gas, ~~marketing~~condensate ~~agreement~~and ~~with~~NGLs ~~ARM~~are ~~through~~sold ~~November~~at ~~30,~~market ~~2019~~prices. ~~With~~We ~~respect~~remit to ~~gas~~the producer an agreed-upon price from the resulting sales, ~~ARM~~which ~~continues~~is totreated ~~collect~~as ~~payments~~product ~~from~~expense. ~~purchasers,~~Collateral ~~deducts~~or ~~their~~other ~~marketing~~security ~~fee~~is ~~and~~generally ~~remits~~not ~~the~~required ~~balance~~with regard to ~~us.~~our trade receivables.

WeDuring ~~also~~most ~~sell~~of ~~our~~the ~~NGL~~first ~~production~~quarter ~~under~~of ~~various~~2019 ~~contracts~~and ~~with~~throughout ~~processors~~2018, inARM ~~the~~Energy ~~vicinity~~Management, ofLLC ~~the~~(“ARM”) ~~production~~marketed atour ~~spot~~oil, ~~market~~gas ~~rates,~~and ~~after~~NGLs ~~processing~~for ~~costs~~a marketing fee that was deducted from sales proceeds collected by ARM from purchasers. ~~Other~~ ~~than~~The ~~our~~sales ~~marketing~~were ~~agreement~~generally made under short-term contracts with ~~ARM,~~month-to-month nopricing ~~other~~based ~~customers~~on ~~accounted~~published regional indices, adjusted for ~~more~~transportation, ~~than~~location ~~10%~~and ofquality. In ~~our~~March ~~consolidated~~2019, ~~sales~~in preparation for ~~the~~handling ~~Successor~~oil ~~Period. We~~and doNGL ~~not~~marketing ~~believe~~responsibilities internally, we began receiving payments for the ~~loss~~sale of ~~any~~oil ~~specific~~and ~~customer,~~NGLs ordirectly offrom ~~our~~purchasers and separately paying the marketing ~~agent~~fee owed to ARM. In June 2019, ~~would~~we ~~have~~terminated aour ~~material~~oil ~~adverse~~and ~~effect~~NGL onmarketing usagreement ~~because~~with ~~alternative~~ARM ~~purchasers~~and ~~are~~began ~~available~~marketing such products internally.

~~The~~For ~~oil~~2019, ~~and~~ARM ~~gas~~marketed ~~production~~$123.0 ~~from our operated STACK acreage~~million, ~~not~~or ~~otherwise~~24.6% ~~previously~~of ~~dedicated,~~our istotal ~~dedicated~~operating torevenue ~~KFM~~ for ~~midstream~~the ~~services~~period.

~~Upstream~~Other ~~Segment~~than ~~Operating~~our ~~Summary~~natural gas marketing agreement with ARM, we had one customer, Phillips 66, that accounted for $202.6 million, or 40.5% of our total operating revenue for 2019.

	Successor		Predecessor
	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
Net production:
Oil (Mbbls)	5,053		494		3,907		2,571
Natural gas (MMcf)	16,913		1,609		13,972		8,259
NGLs (Mbbls)	2,268		151		1,277		824
Total (MBoe)	10,140		914		7,513		4,772
Daily average (MBoe)	31.1		23.4		20.6		13.1
Average sales prices (pre-hedging):
Oil (per bbl)	$	63.99	$	62.68	$	49.76	$	41.15
Natural gas (per Mcf)	2.57		2.66		2.70		2.42
NGLs (per bbl)	18.98		26.41		24.62		17.21
Combined (per Boe)	40.41		42.95		35.10		29.35
Average sales prices (after hedging):
Oil (per bbl)	$	56.64	$	56.24	$	49.42	$	73.25
Natural gas (per Mcf)	2.42		3.60		3.19		3.21
NGLs (per bbl)	18.98		26.41		23.48		16.81
Combined (per Boe)	36.51		41.13		35.64		47.93
Average costs per BOE:
Lease operating expense	$	5.97	$	4.82	$	5.85	$	6.20
Marketing and transportation expense	4.93		4.08		3.92		2.44
Production and ad valorem taxes	1.66		1.04		0.73		0.58
Workover expense	0.55		0.46		0.57		0.72

Table of Contents

Index to Financial Statements

Midstream Segment Operating Summary

	Successor
	February 9, 2018ThroughDecember 31, 2018
Net throughput:
KFM gas volumes (MMcf)	35,058
KFM crude oil gas volumes (Mbbls)	1,739
KFM produced water gathering volumes (Mbbls)	5,320
(In thousands)
Revenues:
Sales of gathered production	$	31,506
Midstream revenue	68,519
Total Midstream sales revenue	$	100,025
Expenses:
Midstream operating	$	15,221
Cost of sales for purchased gathered production	31,247
Transportation and processing	9,911
Depreciation and amortization	27,388
Impairment of assets:
Impairment of Cimarron investment	15,963
Impairment of property, plant and equipment	68,407
Impairment of intangible assets	394,999
Impairment of goodwill	691,970
Total Midstream impairment of assets	1,171,339
General and administrative	14,025
Total operating expenses	$	1,269,131

Seasonality

Weather conditions affect the demand for, and prices of, oil and gas. During the winter, natural gas demand for heating by residential and commercial consumers generally increases whereas high summer temperatures can result in an increase in demand from the power sector. Natural gas in storage typically increases from April through October. Crude oil markets tend to be stronger in the fourth quarter when demand for heating oil is impacted by colder weather and inventory build. Hurricanes and other severe weather (particularly along the Gulf Coast) can also impact supplies by causing disruptions in the level of oil and gas production. Due to these fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Competition

We compete with other companies in all areas of our operations, including, in the past, the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and gas companies and independent oil and gas companies. Many of our competitors are large, well-established companies with substantially greater resources and better credit than us and have been engaged in the oil and gas business for a longer period of time than we have. Our filings for bankruptcy protection and restrictions placed on our spending by the Bankruptcy Court have also put us at a competitive disadvantage. This may allow our competitors to have an advantage over us with respect to:

• ~~acquisitions~~maintaining ofproduction ~~oil~~levels ~~and~~on ~~gas~~existing ~~properties,~~oil ~~exploratory prospects~~ and ~~mineral~~gas ~~leases~~properties;


•	evaluations of properties;


•	utilization of midstream assets; and

Table of Contents

Index to Financial Statements


•	absorption of price changes and the costs and implementation of evolving federal, state and local laws and regulations.

~~We are also affected by competition for drilling rigs and other equipment, including that used in our completion process.~~ In the past, the oil and gas industry has experienced shortages of drilling rigs, equipment, pipe, materials (including drilling and completion fluids) and personnel. ~~These shortages can delay our development, exploitation and exploration activities.~~ We are unable to predict when, or if, such future shortages will occur or their impact on our operations.

With decreased activity in the STACK since 2018, we have seen opportunities to renegotiate our service costs. We believe that we can continue to drive service costs down or maintain the savings that we have captured during 2019, unless there is a spike in commodity prices and industry activity or heightened concerns about our creditworthiness.

Regulatory Environment

Our Upstream and Midstream operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental agencies, including the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Among other things, these laws and regulations may:

Table of Contents

Index to Financial Statements


•	require various permits before drilling and other regulated activities commence;


•	require installation of pollution control equipment and place other conditions on our operations;


•	place restrictions on the use of materials for our operations and upon the disposal of by-products from our operations;


•	restrict the types, quantities and concentrations of various substances that can be released into the environment or used for our operations;


•	limit our operations on lands lying within wilderness, wetlands and other protected areas;


•	require remedial measures to mitigate pollution from former and ongoing operations, including site restoration, pit closure and plugging of abandoned wells; and


•	impose specific safety and health criteria addressing worker protection.

These laws, rules and regulations often impose difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in remedial or corrective action obligations.

Resource Conservation and Recovery Act

The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of non-hazardous and hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. As part of our operations, we generate some amounts of ordinary industrial wastes that may be deemed as hazardous wastes by regulatory authorities. Drilling fluids, produced waters, and most of the other wastes associated with our operations, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that regulations could change and cause wastes now classified as non-hazardous to be classified as hazardous wastes.

Comprehensive Environmental Response, Compensation and Liability Act

The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability on classes of persons considered to be responsible for the release of hazardous substances and other classes of materials. Under CERCLA, such persons may be subject to joint and several, strict liability for costs of investigation and remediation and for damages without regard to fault or legality of the original conduct. These classes of persons, ~~dubbed~~referred to as potentially- responsible- parties (“PRPs”), include the current and past owners or operators of a site where the hazardous substance release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable statutes.

Table of Contents

Index to Financial Statements

Federal Water Pollution Control Act

The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws impose restrictions and controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

Safe Drinking Water Act

Our underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state and local laws and regulations. The UIC program includes administrative requirements for produced water disposal and prohibits migration of fluid containing any contaminant into underground sources of drinking water. State regulations require permits to operate underground injection wells. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative water supplies, property and personal injuries. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced waters and other substances, which could affect our business.

Table of Contents

Index to Financial Statements

liability by third-parties claiming damages for alternative water supplies, property and personal injuries. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced waters and other substances, which could affect our business.

Furthermore, in response to recent seismic events near produced water disposal wells, federal and some state agencies are investigating whether such wells have contributed to increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. In response to these concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for injection wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations.

Clean Air Act

Our operations are subject to the federal Clean Air Act (“CAA”) and comparable state laws and regulations that restrict the emission of air pollutants. These laws and regulations may require us to obtain approval for the construction or modification of certain facilities expected to produce or significantly increase air emissions, comply with stringent air permit requirements and also utilize equipment or technologies to control emissions. Obtaining such permits could delay our operations.

National Environmental Policy Act

Our operations on federal lands may be subject to the federal National Environmental Policy Act (“NEPA”), which requires federal agencies, including the EPA, to evaluate major agency actions having the potential to significantly impact the environment. As part of such evaluations, an agency will conduct an environmental assessment that assesses the potential impacts of a proposed project and may require the preparation of a detailed environmental impact statement for public review and comment. Our current and future operations on federal lands will be subject to NEPA, which could delay or impose additional conditions and costs on us. Moreover, this process could ~~experience~~involve protest, appeal or litigation, any or all of which may impact our operations.

Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statutes ~~whose~~enacted ~~purpose is~~ to protect the health and safety of workers. In addition, comparable state statutes require that we organize and/or disclose information about hazardous materials attendant to our operations to our employees, state and local governmental authorities and citizens.

Table of Contents

Index to Financial Statements

Our processing plant operations are also subject to standards designed to ensure the safety of our processes, such as the Occupational Safety and Health Administration’s Process Safety Management standard, which is designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. The Process Safety Management standard imposes requirements on regulated entities related to managing these hazards. These requirements include conducting process hazard analyses for processes involving highly hazardous chemicals, developing detailed written operating procedures, including procedures for managing change, and evaluating the mechanical integrity of critical equipment. We conduct periodic audits of Process Safety Management systems at each of our locations subject to this standard.

Hydraulic Fracturing

We perform hydraulic fracturing in horizontally drilled wells. Currently, most of our hydraulic fracturing activities are regulated at the state level, asgiven that the EPA only has limited ~~purview~~authority ~~over~~to regulate fracturing activities. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the hydraulic fracturing process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater into surface waters; and disposal or storage of fracturing wastewater in unlined pits.

Clean Air Act

Our operations are subject to the federal Clean Air Act (“CAA”) and comparable state laws and regulations that restrict the emission of air pollutants. These laws and regulations may require us to obtain approval for the construction or modification of certain facilities expected to produce or significantly increase air emissions, comply with stringent air permitting requirements and also utilize equipment or technologies to control emissions. Obtaining such permits could delay our operations.

Table of Contents

Index to Financial Statements

Climate Change Regulations and Legislation

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at all levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential sources of significant pollutant emissions. Sources subject to these permitting requirements must meet “best available control technology” standards for those GHG emissions. Additionally, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including, among others, onshore and offshore oil and gas production, processing, transmission, storage and distribution facilities, which include certain of our operations.

Federal agencies also directly regulate emissions of methane, a GHG, from oil and gas operations. In August 2016, the EPA issued a final New Source Performance Standards (“NSPS”) rule, known as Subpart OOOOa, which requires certain new, modified or reconstructed facilities in the oil and gas sector to reduce ~~these~~ methane gas and volatile organic compound emissions. These Subpart OOOOa standards ~~expand~~expanded the previously issued NSPS published by the EPA in 2012, and known as Subpart OOOO, by using certain equipment-specific emissions control practices. However, in August 2019, the EPA proposed two options for further rescinding the Subpart OOOOa standards. Under the EPA’s preferred alternative, the agency would rescind the methane limits for new, reconstructed and modified oil and natural gas production sources while leaving in place the general emission limits for volatile organic compounds, and relieve the EPA of its obligation to develop guidelines for methane emissions from existing sources. In addition, the proposal would remove from the oil and natural gas category the natural gas transmission and storage segment. The other proposed alternative would rescind the methane requirements of the Subpart OOOOa standards applicable to all oil and natural gas sources, without removing any sources from that source category (and still requiring control of volatile organic compounds in general). Future implementation of this rule is uncertain at this time.

Other Regulation of the Oil and Gas Industry

Our operations are also subject to various other types of regulation at the federal, state and local level. These types of regulations include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate may also regulate:


•	the location of wells;


•	the method of drilling and casing wells;


•	the timing of conducting our activities, including seasonal wildlife closures;


•	the rates of production;


•	the surface use and restoration of properties where we operate;


•	the plugging and abandoning of wells;


•	interactions with surface owners and other third parties; and


•	abandonment of pipelines and midstream facilities.

9State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. We rely upon the Oklahoma “forced pooling” process to facilitate working interest owners’ participation in our operations. Under this process, if a party proposes to drill the initial well to a particular formation in a specific drilling and spacing unit but cannot obtain the agreement of all other oil and gas interest holders and other leaseholders within the unit as to how the unit should be developed, the party may initiate “forced pooling”. Under current regulations, drilling and spacing units for our targeted horizons are based on a maximum of four to eight horizontal wells, depending on the formation, on a 640-acre section. In a forced pooling action, the proposed operator files an application for a pooling order with the Oklahoma Corporation Commission (“OCC”) and names all other persons with the right to drill the unit as respondents. The proposed operator is required to demonstrate that it has made a good faith effort to bargain with all of the respondents prior to filing its application. The fair value of the mineral interests in the unit is determined in an administrative proceeding by reference to market transactions involving nearby oil and gas rights, including nearby mineral lease costs.

Table of Contents

Index to Financial Statements

~~State~~combination, ~~laws~~based ~~regulate~~on the ~~size~~fair ~~and~~value ~~shape~~established ~~of drilling~~ and ~~spacing~~approved ~~units~~through ~~or proration units governing~~ the ~~pooling~~administrative ~~of oil and gas properties~~hearing. The Wepooling ~~rely~~order ~~upon~~typically addresses the ~~Oklahoma~~time ~~“forced~~frame ~~pooling”~~for ~~process~~drilling ~~to facilitate working interest owners’ participation in our operations. Under this process, if a party proposes to drill~~ the ~~initial~~ well ~~to a particular formation in a specific drilling~~ and ~~spacing~~provides ~~unit~~for ~~but cannot obtain~~ the ~~agreement~~manner ofin ~~all~~which ~~other~~future ~~oil~~wells ~~and gas interest holders and other leaseholders~~ within the unit asmay ~~to how the unit should~~ be ~~developed, the party may initiate “forced pooling”~~drilled. The ~~Under~~applicant ~~current regulations, drilling and spacing units~~ for ~~our targeted horizons are based on a maximum of four to eight horizontal wells, depending on~~ the ~~formation, on a 640-acre section. In a forced~~ pooling ~~action, the proposed operator files an application for a pooling~~ order ~~with~~is ~~the~~ordinarily ~~Oklahoma~~designated ~~Corporation~~as ~~Commission (“OCC”) and names all other persons with~~ the ~~right to drill the unit as respondents. The proposed~~ operator ~~is required to demonstrate that it has made a good faith effort to bargain with all~~ of the ~~respondents~~wells ~~prior~~subject to ~~filing its application. The fair value of~~ the ~~mineral~~pooling ~~interests in the unit is determined in an administrative proceeding by reference to market transactions involving nearby oil and gas rights, including nearby mineral lease costs~~order.

Assuming the application for a forced pooling order is granted, the respondents then have 20 days to elect either to participate in the proposed well or accept fair value for their interest, usually in the form of a cash payment, an overriding royalty, or some combination, based on the fair value established and approved through the administrative hearing. The pooling order typically addresses the time frame for drilling the well and provides for the manner in which future wells within the unit may be drilled. The applicant for the pooling order is ordinarily designated as the operator of the wells subject to the pooling order.

The availability of forced pooling normally means that it is difficult for a small number of owners to block or delay the drilling of a particular well proposed by another interest holder. Oil and gas companies in Oklahoma generally attempt to lease as much of the mineral interests in a particular area as are readily available at acceptable rates, and then use the forced pooling process to proceed with the desired development of the well. In this manner, we have the ability to expand into and develop areas near our existing acreage even if we are unable to lease all of the mineral interests in those areas.

The gross production tax, or severance tax, is a value-based tax levied at a basic rate of 7% upon the production of oil and gas in Oklahoma. As an economic incentive to develop its resources, Oklahoma has historically offered a “tax holiday” with rates ranging from 1% for 48 months to 2% for 36 months for production from horizontal wells. Through June 2018, Oklahoma imposed a tax of 2% of gross production for the first 36 months of production and then at 7% thereafter on wells drilled after July 1, 2015. Effective July 2018, the 2% tax rate was increased to 5% for wells drilled after July 1, 2015 that were still within their first 36 months of production. For the period beyond 36 months, the tax rate remains at 7% for the remaining productive life of each well. All wells drilled after July 1, 2018 are taxed at 5% of gross production for the first 36 months of production and then at 7% thereafter. In addition, a longstanding excise tax of 0.095% continues to be levied.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations covering these procedures. Some state agencies and municipalities have binding requirements related thereto.

Regulation of Natural Gas Sales and Transportation

The rates, terms and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the Federal Energy Regulatory Commission (the “FERC”), as common carriers, under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In March 2016, the PHMSA issued a Notice of Proposed Rulemaking proposing to revise the Pipeline Safety Regulations applicable to the safety of onshore gas transmission and gathering pipelines, including both high consequence areas (“HCAs”) and non-HCAs. In October 2019, PHMSA submitted three major rules to the Federal Register, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called gas Mega Rule), the safety of hazardous liquid pipelines, and enhanced emergency order procedures. The gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA is expected to issue the second and third parts of the gas Mega Rule in the near future. The safety and hazardous liquid pipelines rule would extend leak detection requirements to all non-gathering hazardous liquid pipelines and require operators to inspect affected pipelines following extreme weather events or natural disasters to address any resulting damage. Finally, the enhanced emergency procedures rule focuses on increased emergency safety measures. In particular, this rule increases the authority of PHMSA to issue an emergency order that addresses unsafe conditions or hazards that pose an imminent threat to pipeline safety.

10Any transportation of our crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA, and the DOT’s Federal Railroad Administration (“FRA”)

Table of Contents

Index to Financial Statements

~~Safety~~under the Hazardous Materials Regulations ~~applicable~~at 49 CFR Parts 171-180, including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the ~~safety~~consequences of ~~onshore~~train ~~gas~~accidents ~~transmission~~ and ~~gathering~~the increase in the rail transportation of flammable liquids. In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including ~~both~~a ~~high~~requirement ~~consequence~~that ~~areas~~all ~~(“HCAs”)~~hazardous liquid pipelines have a system for detecting leaks and ~~non-HCAs~~establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters.

Any transportation of our crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA, and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids. In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters.

Gathering Pipeline Regulation

Section 1(b) of the Natural Gas Act of 1938 (“NGA”), exempts natural gas gathering facilities from regulation by the FERC under the NGA. We believe that our Midstream assets meet the tests the FERC has used to determine exemption from its jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services.

Other

The oil and gas industry is also subject to other federal, state and local regulations and laws relating to resource conservation and employment standards.

Employees

As of ~~June 28~~December 31, 2019, we had ~~154~~151 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.

Insurance

We maintain customary insurance against some, but not all, of the operating risks to which our business is exposed. Wesuch ~~currently~~as ~~have policies in place that cover~~ general liability (includes sudden and accidental pollution), physical damage to our assets, control of wells, auto liability, worker’s compensation and employer’s liability.

We regularly execute master services contracts with our third-party vendors, suppliers and contractors in which they agree to indemnify us for injuries and deaths of their employees and contractors. Similarly, we generally agree to indemnify them against claims made by our other vendors, suppliers, contractors and employees. Additionally, each party ~~generally~~ is generally responsible for damage to its own property.

Executive Officers

Our executive officers and their ages as of July 31, 2019, are set forth below:

Name	Age	Position
James T. Hackett	65	Executive Chairman of the Board and Interim Chief Executive Officer
Randy L. Limbacher	61	Interim President
John C. Regan	49	Executive Vice President, Chief Financial Officer and Assistant Secretary
John H. Campbell, Jr.	61	Interim Executive Vice President and Chief Operating Officer
Kimberly O. Warnica	45	Executive Vice President, General Counsel, Chief Compliance Officer and Secretary
Mark P. Castiglione	48	Interim Executive Vice President - Strategy and Corporate Development

James T. Hackett became our Executive Chairman of the Board immediately following the closing of the Business Combination and was named Interim Chief Executive Officer on December 26, 2018. He also briefly served as Chief Operating Officer— Midstream from February 9, 2018 until April 2018 and now serves as President of the Company’s subsidiary KFM. Prior to the Business Combination, he served as our Chief Executive Officer and director since March 2017. Mr. Hackett is a Senior Advisor to Riverstone Investment Group, LLC. Prior to joining Riverstone in 2013, Mr. Hackett served as the Chairman of the Board from 2006 to 2013 and the Chief Executive Officer from 2003 to 2012 of Anadarko Petroleum Corporation.

Table of Contents

Index to Financial Statements

Before joining Anadarko, Mr. Hackett served as President and Chief Operating Officer of Devon Energy Corporation, following its merger with Ocean Energy, where he had served as Chairman, President, and Chief Executive Officer. Mr. Hackett has held senior positions at Seagull, Duke Energy, and Pan Energy. He also held positions in engineering, finance and marketing in the midstream, oil field services, and power sectors of the energy industry. Mr. Hackett serves on the Board of Directors of Enterprise Products Holdings, LLC, Fluor Corporation and National Oilwell Varco, Inc. Mr. Hackett is a former Chairman of the Board of the Federal Reserve Bank of Dallas. Mr. Hackett received a Bachelor of Science degree from the University of Illinois in 1975 and an MBA and MTS from Harvard University in 1979 and 2016, respectively.

Randy L. Limbacher became our Interim President on January 1, 2019. He also serves as the Chief Executive Officer of Meridian Energy LLC (a Houston-based energy advisory firm), a position he has held since June 2017. He currently serves on the board of directors of CARBO Ceramics Inc. and TC Energy Corporation (formerly TransCanada Corporation). From March 2017 to June 2017, Mr. Limbacher managed his personal investments as a private investor. From April 2013 until December 2015, Mr. Limbacher served as President, Chief Executive Officer and a Director of Samson Resources Corporation, a Tulsa-based oil and gas company, which filed for Chapter 11 protection in September 2015. Mr. Limbacher served as Vice Chairman of the Board of Directors of Samson from December 2015 until the company emerged from bankruptcy in March 2017. From November 2007 until February 2013, Mr. Limbacher served as President and Chief Executive Officer and a Director of Rosetta Resources, Inc., a Houston-based oil and gas company. From February 2010 until February 2013, Mr. Limbacher also served as Chairman of the Board of Rosetta. From April 2006 until November 2007, Mr. Limbacher held the position of President, Exploration and Production - Americas for ConocoPhillips, a Houston-based energy company. Prior to that time, Mr. Limbacher spent over twenty years with Burlington Resources Inc., a Houston-based oil and gas company, where he served as Executive Vice President and Chief Operating Officer from 2002 until it was acquired by ConocoPhillips in April 2006. He was a Director of Burlington Resources from January 2004 until the sale of the company. Mr. Limbacher received a Bachelor of Science degree in petroleum engineering from Louisiana State University in 1980.

John C. Regan was named Executive Vice President, Chief Financial Officer and Assistant Secretary on June 18, 2019. Prior to joining us as Vice President, Chief Financial Officer and Assistant Secretary on January 7, 2019, Mr. Regan served as the Chief Financial Officer of Vine Oil and Gas LP from January 2015 to June 2018. He previously served as Chief Financial Officer of Quicksilver Resources from April 2012 through December 2014, after having served as their Chief Accounting Officer beginning in September 2007. Mr. Regan is a Certified Public Accountant with more than 25 years of combined public accounting, corporate finance and financial reporting experience.

John H. Campbell, Jr. became our Interim Executive Vice President and Chief Operating Officer on June 18, 2019. Mr. Campbell initially joined us on January 1, 2019 as Interim Chief Operating Officer - Upstream. He also serves as President and Chief Operating Officer of Meridian Energy LLC, a position he has held since June 2017. From June 2016 to June 2017, Mr. Campbell served as a partner of Quantum Energy Partners, LLC. Prior to joining Quantum Energy Partners, LLC, he served as President of QL-Energy, LLC. From 2010 to 2014, Mr. Campbell served as President and Chief Operating Officer of QR Energy, LP. From 2008 to 2015 Mr. Campbell served as President and Chief Operating Officer of Quantum Resources Management, LLC. Mr. Campbell received a Bachelor of Science degree in petroleum engineering from the University of Alabama, Tuscaloosa in 1983 and a Master of Engineering degree in petroleum engineering degree from Texas A&M University in 1987.

Kimberly O. Warnica was named Executive Vice President, General Counsel, Chief Compliance Officer and Secretary on June 18, 2019. Ms. Warnica initially joined us in April 2018 as our Vice President, General Counsel, Chief Compliance Officer and Secretary. Prior to joining us, Ms. Warnica served as Assistant General Counsel and Assistant Secretary at Marathon Oil Corporation since April 2017. She previously served as Group Counsel and Assistant Secretary of Marathon Oil from October 2016 until April 2017. Prior to Marathon Oil, Ms. Warnica served as Assistant General Counsel and Assistant Secretary at Freeport-McMoRan Oil & Gas (formerly Plains Exploration and Production Company) from April 2006 until June 2016. She started her career at Andrews Kurth LLP where she practiced corporate and securities law representing a variety of clients in numerous transactional, securities and corporate governance matters. Ms. Warnica has a Bachelor’s degree from Texas A&M University and earned her J.D. from the University of Texas School of Law.

Mark P. Castiglione became our Interim Executive Vice President - Strategy and Corporate Development on June 18, 2019. He initially joined us as Chief of Staff to the President on January 1, 2019. He also serves as Executive Vice President of Meridian Energy LLC, a position he has held since June 2017. From January 2015 to May 2017, Mr. Castiglione managed MPC Resources, LLC (an energy advisory firm) and was engaged as Senior Advisor to SandRidge Energy, Inc. from January 2015 to June 2016. From 2010 to December 2014, he served as Senior Vice President – Business Development of Quantum Resources Management, LLC and QR Energy, LP. Prior to joining Quantum Resources, Mr. Castiglione served as Vice President –

Table of Contents

Index to Financial Statements

Acquisitions and Divestitures of El Paso Corporation from 2009 to 2010 and Vice President – Business Development of El Paso Exploration and Production from 2008 to 2009. Mr. Castiglione’s prior background at Encana Corporation, Burlington Resources and Simmons & Company International includes positions of increasing responsibility in corporate development, corporate finance, asset management and engineering. He began his career in 1994 as a reservoir engineer at Burlington Resources. Mr. Castiglione received a Bachelor of Science degree in petroleum engineering from Texas Tech University in 1993 and a Master of Business Administration degree from the Cox School of Business at Southern Methodist University in 1999.

Available Information

We ~~periodically~~ disseminate information about the Company through required filings we make with the SEC and, at our discretion, on our website at www.altamesa.net. ~~Information~~In ~~contained~~February on2020, orwe ~~connected~~filed toforms ~~our~~with ~~website~~the isSecurities ~~not incorporated by reference into this Annual Report~~ and ~~should~~Exchange ~~not~~Commission beto ~~considered~~deregister ~~part~~our ofClass ~~this~~A ~~Annual~~Common ~~Report~~Stock orand ~~any~~warrants ~~other~~under ~~filings~~Section we12(g) ~~make~~of ~~with~~ the ~~SEC. The~~Securities ~~SEC~~Exchange ~~maintains~~Act aof ~~site~~1934, ~~that~~as ~~contains reports~~amended, ~~proxy~~(the ~~and~~“Exchange ~~information~~Act”) ~~statements~~ and ~~other~~suspend ~~information~~our ~~regarding~~ reporting ~~issuers. Our~~obligations ~~annual~~under ~~reports~~Sections on13 ~~Form 10-K, quarterly reports on Form 10-Q~~ and ~~current~~15(d) ~~reports on Form 8-K are filed electronically and are available free~~ of ~~charge~~the atExchange ~~http://www~~Act.~~sec.gov. Additionally~~ Accordingly, ~~the~~we ~~Company~~do ~~will~~not ~~provide~~anticipate ~~electronic~~filing orany ~~paper~~additional ~~copies free of charge upon request to our Secretary at 15021 Katy Freeway~~current, ~~Suite~~quarterly ~~400, Houston, Texas 77094~~ or byannual ~~calling~~reports ~~(281)~~with ~~530-0991~~the SEC.

Information contained on or connected to our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report or any other filings we make with the SEC. The SEC maintains a site that contains reports, proxy and information statements and other information regarding reporting issuers. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K are filed electronically and are available free of charge at http://www.sec.gov. Additionally, the Company will provide electronic or paper copies free of charge upon request to our Secretary at 15021 Katy Freeway, Suite 400, Houston, Texas 77094 or by calling (281) 530-0991.

Item 1A. Risk Factors

~~Investing~~Not ~~in our securities involves a high degree of risk~~required. You should consider carefully the risks and uncertainties described below, together with all of the other information in this Annual Report, including our consolidated financial statements and related notes, before deciding whether to purchase any of our securities.

Each of the following risk factors could adversely affect our business, operating results and financial condition (which we individually and/or collectively refer to as having “an adverse effect on us.” It is not possible to foresee or identify all such factors. Investors should not consider this list as an exhaustive statement of all risks and uncertainties. This report also contains forward-looking statements that involve risks and uncertainties. Our actual results may differ from those anticipated in these forward-looking statements as a result of both the risks described below and factors described elsewhere in this Annual Report. Please read the section above entitled “Cautionary Statement Regarding Forward-Looking Statements” for further discussion of these matters.

Going Concern Risk

Our ability to continue as a going concern contemplates the realization of assets and the satisfaction of liabilities in the normal course of business, including the effective implementation and success of our plans to mitigate the conditions that raise substantial doubt about our ability to continue as a going concern.

Our consolidated financial statements have been presented on the basis that we would continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. Our liquidity and ability to comply with debt covenants under the Alta Mesa RBL and the KFM Credit Facility have been negatively impacted by increased borrowings, the recent decrease in forecasted production levels and increased operating costs in 2018 in our Upstream business, in addition to the pressures created by lower commodity prices in late 2018 and early 2019. Additionally, we failed to timely provide our lenders under the KFM Credit Facility with quarterly financial statements for the quarter ended December 31, 2018, and we failed to provide our lenders notice in connection with KFM’s acquisition of the produced water assets from Alta Mesa, including the delivery of certain recorded instruments of transfer. In April 2019, we entered into an amendment and limited waiver (the “Amendment”) to the KFM Credit Facility to waive the defaults and events of default arising or resulting from those failures. The Amendment adds provisions which limit the maximum amount of cash KFM can hold to $15.0 million. The Amendment also generally provides that any amendment to a material contract with an affiliate during a six-month period that causes a reduction to projected revenue by more than 15% constitutes an event of default. We also subsequently provided the lenders the required quarterly financial statements and recorded instruments of transfer in connection with the Amendment.

Table of Contents

Index to Financial Statements

Based on our current operating and commodity price forecast and our current capital structure, and in the absence of the consummation of one or more of the deleveraging transactions discussed below, we do not anticipate being able to maintain compliance with the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of September 30, 2019. In August 2019, the lenders exercised their ability to make an optional redetermination of the borrowing base under the Alta Mesa RBL ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200.0 million effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceed the new borrowing base by $162.4 million, we have five months to make ratable payments of $32.5 million each month to cause utilization to be less than or equal to the borrowing base. If we are unable to make this repayment, we will be in default under the Alta Mesa RBL. The uncertainty related to our continued compliance with the terms of the Alta Mesa RBL and the potential for lenders under the Alta Mesa RBL to further reduce the borrowing base raise substantial doubt regarding Alta Mesa’s ability to continue as a going concern. Should Alta Mesa be required to seek protection under laws governing bankruptcy before July 2020, we believe there is a risk that it or the courts could attempt to reject or alter agreements between KFM and Alta Mesa that would cause KFM’s consolidated revenues to be negatively impacted by more than 15%, which would constitute an event of default under the KFM Credit Facility, as amended, giving our lenders the ability to accelerate repayment of all outstanding amounts. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern, however we have reclassified all of Alta Mesa’s debt as current liabilities.

In March 2019, our Board authorized the retention of financial advisors to assist in evaluating the available financial alternatives, including without limitation:

• amending or waiving the covenants or other provisions of our debt;

• raising new capital in private or public markets; and

• taking other actions to address our balance sheet either in court or through an out of court agreement with creditors.

We are also considering operational matters such as reducing our forecasted capital plan. Any action or combination of such actions may be unsuccessful in attaining compliance with the covenants under the Alta Mesa RBL and the KFM Credit Facility.

If an agreement is reached with our creditors and we pursue a restructuring, it may be necessary for us, or our subsidiaries, to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in order to implement the agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court in the bankruptcy proceedings. We also may conclude that it is necessary to initiate Chapter 11 proceedings to implement a restructuring of our obligations even if we are unable to reach an agreement with our creditors and other relevant parties regarding the terms of such a restructuring. If a plan of reorganization is implemented in a bankruptcy proceeding, it is possible that holders of claims and interests with respect to, or rights to acquire, our equity securities would be entitled to little or no recovery, and those claims and interests may be canceled for little or no consideration. If that were to occur, we anticipate that all or substantially all of the value of all investments in our equity securities would be lost and that our equity holders would lose all or substantially all of their investment. It is also possible that our stakeholders, including our secured and unsecured creditors, will receive substantially less than the amount of their claims.

Risks Related to our Upstream Business

Oil, gas and NGL prices are highly volatile and a sustained decrease in prices can significantly and adversely affect our financial condition, results of operations and the carrying value of our assets.

Historically, the markets for oil, gas and NGLs have been volatile and are likely to continue to be volatile in the future, causing prices to fluctuate widely. Factors influencing the prices of oil, gas and NGLs are beyond our control. These factors include, but are not limited to, the following:

• domestic and worldwide supply of, and demand for, oil, gas and NGLs;

• volatility and trading patterns in the commodity-futures markets;

• the cost of exploring for, developing, producing, transporting and marketing oil, gas and NGLs;

• the level of global oil and gas inventories;

• weather conditions;

• the level of U.S. exports of oil, LNG or NGLs;

• the ability of the members of OPEC and other producing nations to agree to and maintain production levels;

Table of Contents

Index to Financial Statements

• the worldwide military and political environment, civil and political unrest worldwide, including in Africa and Middle East, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities, or acts of terrorism in the United States or elsewhere;

• the effect of worldwide energy conservation and environmental protection efforts;

• the price and availability of alternative and competing fuels;

• the value of the dollar relative to the currencies of other countries;

• the level of foreign imports of oil, gas and NGLs;

• domestic and foreign governmental laws, regulations and taxes;

• stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and gas;

• the proximity to, and capacity of, gas pipelines and other transportation facilities; and

• general economic conditions worldwide.

The long-term effects of these and other factors on the prices of oil, gas and NGLs are uncertain. Historical declines in commodity prices have adversely affected our business by:

• reducing the amount of oil, gas and NGLs that we can produce economically;

• reducing our liquidity, revenue, operating income and cash flows;

• causing us to reduce our capital expenditures and delay or postpone some of our capital projects;

• causing reductions to the Alta Mesa RBL borrowing base, which negatively impacts our borrowing ability;

• causing contraction of available trade credit;

• pressuring our ability to meet financial covenants under our debt agreements;

• triggering impairments of our long-lived assets;

• reducing the value of our future net cash flows from our oil and gas properties;

• increasing the costs of obtaining capital, such as equity and short- and long-term debt; and

• adversely affecting the ability of our partners to fund their working interest capital requirements.

In April 2019, we removed all of our PUD reserves effective as of December 31, 2018, due to our assessment of our potential inability to fund the associated development costs. Lower oil, gas and NGL prices and any corresponding reduction in our capital expenditure budget and drilling program could cause us to further reduce our estimates of production, which could reduce the value of our oil and gas properties.

Our operations, including development and acquisitions, will require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

Our industry is capital intensive. We have made and expect to continue to make substantial capital expenditures for the exploration, exploitation, development and acquisition of oil and gas reserves. Due to the price environment in late 2018 and early 2019, we have substantially decreased our planned capital expenditures for 2019 compared to 2018. Prior to the August 2019 redetermination of the Alta Mesa RBL, we had anticipated upstream capital expenditures for 2019 to range between $160 million to $180 million, principally for the drilling and completion of wells, expenditures for facilities and acquisition of leasehold, but we are evaluating whether this level of capital is appropriate following that redetermination. Our upstream capital expenditures for 2018 were substantially higher. Given our reduced capital plan for 2019, we are currently estimating a decline in production during the latter half of 2019. This decline in production, as well as other factors, such as lower oil, gas and NGL prices or declines in reserves may lead to reductions in our revenue and operating cash flow and may limit our ability to obtain the capital necessary to sustain our operations at desired levels, which could materially and adversely affect us.

We funded our 2018 upstream capital program primarily through equity capital raised from the Business Combination, borrowings under the Alta Mesa RBL and operating cash flow. We intend to finance our 2019 and future capital expenditures predominantly with cash flow from operations and borrowings under the Alta Mesa RBL, which we drew upon in April 2019 to substantially exhaust remaining capacity.

If necessary, and if permitted under the agreements governing our indebtedness, we may also access capital through proceeds from potential asset dispositions and the future issuance of debt and/or equity securities. Our cash flow from operations and access to capital are subject to several variables, including:

• the estimated quantities and value of our proved oil and gas reserves;

• the amount of oil and gas we produce from existing wells;

Table of Contents

Index to Financial Statements

• the prices at which we sell our production; and

• our ability to acquire, locate and produce new reserves.

On April 1, 2019, in connection with a semi-annual borrowing base redetermination, our borrowing base under the Alta Mesa RBL was reduced from $400 million to $370 million, substantially all of which is currently utilized. In August 2019, the lenders exercised their option to conduct an optional redetermination, pursuant to which they established a revised borrowing base of $200.0 million, which will require us to make monthly installments of $32.5 million for five months beginning in September 2019. As a consequence of reduced operating cash flow and a lowered borrowing base, we have limited ability to obtain the capital necessary to conduct our operations at desired levels. Additionally, if we are in default under the Alta Mesa RBL, the lenders could cease making amounts available, accelerate payment of amounts outstanding or seek other remedies any of which would further limit our access to the capital necessary to fund our capital expenditures. The Alta Mesa RBL may restrict our ability to obtain new debt financing. If additional capital is required, we may not be able to obtain debt and/or equity financing on terms favorable to us, or at all. If cash generated by operations or liquidity available under the Alta Mesa RBL is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our capital expenditures, which in turn could lead to a decline in our reserves and production, forfeiture of leasehold interests and the sale of our assets on an untimely or unfavorable basis, each of which could have a material adverse effect on us.

Our business strategy involves the use of technology, which involves risks and uncertainties in its application.

Our operations involve the use of the latest horizontal drilling, completion and production technologies in an effort to provide for more efficient or inexpensive recovery of hydrocarbons. Although our development plan for 2019 relies upon less innovation than in prior years, our use of emerging technologies may not prove successful and could result in unexpected cost increases or decreases to production or the expected recoverability of reserves and in extreme cases, the abandonment of a well. While horizontal development has become more common in our industry, we may still face difficulties in drilling horizontal wells such as:

• landing our wellbore in the desired drilling zone;

• staying in the desired drilling zone while drilling horizontally through the formation;

• running our production casing the entire length of the wellbore; and

• running tools and other equipment consistently through the horizontal wellbore.

The difficulties that we face while completing our wells include the following:

• designing and executing the optimum fracture stimulation program for a specific target zone;

• running tools through the entire length of the wellbore during completion operations; and

• cleaning out the wellbore after completion of the fracture stimulation.

Certain of the techniques may cause irregularities or interruptions in production due to offset wells being shut-in and the time required to drill and complete multiple wells before any such wells begin producing. Producing wells can be impacted by nearby completion operations which typically require nearby producing wells to de-water before production can resume. We have received, and are likely to continue to receive, claims alleging damage from our fracture and stimulation procedures on adjacent wellbores completed in the same geological interval and in other “associated” geological formations located above or below the target formation. These claims are inherently uncertain, and outcomes cannot be predicted.

Furthermore, the application of technology in one productive formation may not be successful in other prospective formations with little or no horizontal drilling history. If our use of the emerging technologies does not prove successful, our resulting production may be less than anticipated or we may experience cost overruns, timing delays or abandonment of a well. As a result, the return on our investment will be adversely affected and we could incur material write-downs of our assets, both of which could have a material adverse effect on us.

Our oil and gas properties are located in a limited geographic area, making us vulnerable to risks associated with having geographically concentrated operations.

Our oil and gas properties are geographically concentrated in a portion of the STACK which causes our success and profitability to be disproportionately exposed to regional factors relative to our competitors that have more geographically dispersed operations. These factors include, among others: (i) the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors, including midstream capacity constraints; (ii) the access to and

Table of Contents

Index to Financial Statements

availability of rigs, equipment, oil field services, supplies and labor; and (iii) the availability of and access to processing and refining facilities. In addition, we may have a heightened risk to the adverse effects of severe weather events such as floods, ice storms and tornadoes, which can disrupt operations and intensify competition and risk of unavailability of the items described above. The geographic concentration of our operations also increases our exposure to changes in local laws and regulations, wildlife protection stipulations and other unexpected regional events such as natural disasters, seismic events, industrial accidents or labor difficulties. Any one of these events has the potential to disrupt our operations which could have a material adverse effect on us.

Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter our ability to conduct development activities.

Our management team has specifically identified and scheduled the prospective drilling locations on our existing acreage. Our ability to develop our identified locations depends on a number of uncertainties, including oil, gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of necessary field services and equipment, midstream constraints, access to and availability of water to conduct development, regulatory approvals and other factors. Because of these uncertainties, we do not know if the locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these locations. In addition, unless we meet the development timing requirements on our undeveloped acreage, the leases covering such acreage may expire, causing us to lose the opportunity of future development. As such, our actual drilling activities may materially differ from our current expectations.

Our current estimated drilling locations are based on the spacing pattern that we believe will maximize the economic returns associated with development. If our expectations about well results with such spacing pattern prove incorrect, there could be a material reduction to our estimated drilling locations and inventory life.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to access or raise the capital required. Any drilling activities we conduct on these locations may be unsuccessful which would limit our ability to add proved reserves or result in a downward revision of our estimated recoveries, which could have a material adverse effect on us.

Our undeveloped properties include leases that will expire over the next several years if production is not established on units containing that acreage.

Leases on oil and gas properties typically have a term of three to five years, after which they expire unless renewed or, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. Although the majority of our reserves are located on leases that are held by production, the leases included in our unproved properties typically have provisions whereby a lease will expire at the end of the lease term unless certain conditions are met, such as commencement of drilling or the existence of production in paying quantities within defined time periods. A reduction to our drilling program, lower commodity prices or our inability to fund our capital program could cause some of our unproved inventory to become unrealizable, be subject to lease expiration or require us to incur renewal or extension costs. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. This could result in a reduction in our acreage and growth opportunities (or the incurrence of significant costs). Our drilling plans for undeveloped acreage are also subject to change based upon various factors, including drilling results, oil, gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

We depend on development of reserves and upon consummation of acquisitions to maintain our reserve base and revenue.

In general, the volume of production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. For example, we estimate that our base production has a decline rate of approximately 40%. Thus, absent development of reserves or acquisition of properties that have existing proved developed reserves, our revenue could decline as reserves are produced. Our future oil and gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Our reduced drilling program for 2019 could negatively affect our ability to replace reserves and maintain our current production levels, which could have a material adverse effect on us. Additionally, to the extent our operating cash flow falls below projections and external sources of capital become limited or unavailable, our ability to conduct the capital investment to maintain or expand our asset base would be impaired.

Table of Contents

Index to Financial Statements

We recognized material impairments to our Upstream and Midstream assets during 2018. Lower oil, gas and NGL prices or adverse changes in our own operational performance may trigger additional impairments which could have a material adverse effect on us.

We may recognize further significant impairments of our proved and unproved oil and gas properties or other long-lived assets as a result of lower forecasted commodity prices, results of our development activities, reductions to our drilling plans or other material issues related to our businesses. As a result, we may be forced to write-down or write-off assets, restructure our operations, or incur impairment or other charges that could result in accounting losses. Even though these charges may be non-cash items and may not have an immediate impact on our liquidity, the fact that we report charges of this nature could lead to negative market perceptions about us or our securities. In addition, charges of this nature may result in our inability to obtain future financing on favorable terms, or at all.

GAAP requires that we periodically review the carrying value of our properties and other long-lived assets for possible impairment. Based on prevailing commodity prices and 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, we may be required to impair our assets further.

Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

Numerous uncertainties are inherent in estimating quantities of oil and gas reserves. Our estimation of proved reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding production levels and operating and development costs. Although the SEC has established a rule specifying the commodity prices that are incorporated into our proved reserve estimates, the prices that we use in estimating the fair value require us to develop future oil, gas and NGL prices in line with forward market expectations. We also estimate well costs and operating expenses based on recent experience, but these estimates could prove inaccurate. As a result, estimated quantities of proved reserves and projections of future cash flows and production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates to reflect actual drilling results and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil and gas, the classifications of reserves based on risk of recovery and estimated future net cash flows. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Sustained lower prices will cause the 12-month weighted average price to decrease over time as the lower prices are reflected in the average price, which may result in reductions to the estimated quantities and present values of our reserves.

The standardized measure of our proved reserves will not be the same as the current fair value of our oil and gas properties.

We do not believe that the present value of future net revenue from our proved reserves represents the fair value of our oil and gas properties. In accordance with SEC requirements, we based the estimated discounted future net cash flows from our proved reserves on the 12-month unweighted arithmetic average of the closing prices on the first day of each month for the preceding 12 months without giving effect to derivatives. Actual future net cash flows from our oil and gas properties will be affected by factors such as:

• actual prices we receive for our production, including the effects of our hedging program;

• actual cost of development and production expenses;

• the amount and timing of actual production;

• transportation and processing cost and availability; and

• changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with our operations will affect the timing and amount of actual future net revenue and thus our oil and gas properties’ actual present value. In addition, the 10% discount factor we use in the standardized measure may not be the most appropriate discount factor to utilize in determining the fair value of our oil and gas properties. Actual future prices and costs may also differ materially from those used in the present value estimate.

Table of Contents

Index to Financial Statements

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes‑Oxley Act and the NASDAQ, may strain our resources, increase our costs and divert management’s attention, and we may be unable to comply with these requirements in a timely or cost‑effective manner.

As a public company, we incur significant legal, accounting and other expenses that we would not incur as a private company. We also incur costs associated with our public company reporting requirements and with corporate governance requirements, including requirements under the Sarbanes-Oxley Act, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority. These rules and regulations increase our legal and financial compliance costs and make some activities more time-consuming and costly. These rules and regulations make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our Board or as executive officers.

Commencing December 31, 2018, we became a "large accelerated filer" and, accordingly, no longer qualify as an emerging growth company and are no longer able to rely on certain exemptions that were available to us as an emerging growth company. Legal, accounting, administrative and other costs and expenses may increase in the future as we continue to incur both increased external audit fees as well as additional spending to ensure continued regulatory compliance.

We rely on drilling to increase our levels of production. Our production levels will be adversely affected by the planned reductions in our capital program.

A key component to our business strategy is to increase production levels by drilling wells. Although we were successful in elevating production levels during 2018, we cannot provide assurance that we will be able to maintain or grow production levels in the future. For example, our reduced drilling program for 2019 and our limited capital availability could negatively affect our ability to maintain or increase production levels and we are currently estimating a decline in production for each quarter in 2019. We may be unable to accelerate our drilling program in future years to make up for lost production which could have a material adverse effect on us.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow. Acquisitions that we do complete could be on terms that prove to be uneconomic.

We have made and expect to make future acquisitions of businesses or properties that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. We may not be able to obtain contractual indemnities from sellers for liabilities incurred prior to our acquisition.

The success of any completed acquisition will depend on our ability to integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets or to minimize any unforeseen operational difficulties could have a material adverse effect on us.

In addition, our debt agreements impose certain limitations on our ability to enter into mergers or combinations transactions and our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.

Our business is subject to operational risks that will not be fully insured, which could adversely affect us.

Our business activities are subject to operational risks, including:

• damages or disruptions caused by natural disasters such as earthquakes and adverse weather conditions;

• facility or equipment malfunctions;

• pipeline or tank ruptures or spills;

• surface fluid spills and water contamination;

• fires, blowouts, well collapses and explosions; and

• uncontrollable flows of oil or gas or other well fluids.

Table of Contents

Index to Financial Statements

In addition, a portion of our gas production is processed to separate NGLs. If the processing plants that service us were to cease operations, we would need to arrange for alternative transportation and processing facilities, which may not be available. If unavailable, we might have to shut in our gas and, therefore, other production, which could reduce our operating cash flow. Further, any alternative facilities could be more expensive than the facilities we currently use.

Any of these types of events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension or termination of operations and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in our industry, we maintain insurance against some, but not all, of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of insurance exceeds our perceived risks. Losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on us.

Drilling for and producing oil and gas are high risk activities with many uncertainties that could adversely affect us.

Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and gas production.

Our decisions to develop or purchase properties will depend on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. As addressed elsewhere in our Risk Factors, this variability in interpretations presents risk for us. Further, many factors may curtail, delay or cancel our contemplated capital activities, including:

• delays imposed by regulatory bodies or from regulatory compliance, including regulations imposed on produced water disposal;

• regulation limiting the emission of GHGs;

• well set-back legislation or regulation;

• regulation limiting hydraulic fracturing;

• unexpected pressure or irregularities in geological formations;

• shortages of or delays in obtaining equipment, qualified personnel or water for hydraulic fracturing;

• equipment failures, accidents or other unexpected operational events;

• lack of available gathering facilities or delays in construction of gathering facilities;

• lack of available capacity on interconnecting transmission pipelines;

• adverse weather conditions;

• issues related to compliance with environmental regulations;

• environmental hazards, such as leaks, spills, ruptures and unauthorized discharges of fluids and gases associated with our operations;

• declines in oil and gas prices;

• limited availability of financing at acceptable terms; and

• title problems.

Our derivative program could result in financial losses or could reduce our net income.

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and gas, we regularly enter into derivatives (“hedges”) covering a significant portion of our expected production. The Alta Mesa RBL requires us to hedge at least 50% of anticipated equivalent production of our PDP reserves for the upcoming twenty-four month period at each measurement date, but also imposes maximum hedging levels for each production stream. Details of our derivative assets are included in Item 8. If we experience a sustained material interruption in our production, we might be forced to make payments under our hedging program without the benefit of the proceeds from our sale of the underlying production, which would have a material adverse effect on us. Further, risk exists that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge, although all of the counterparties to our current portfolio are lenders under the Alta Mesa RBL. Under that agreement, if a counterparty is a lender and does not perform, then the non-performance is treated as a reduction to the borrowings outstanding. Furthermore, given our current financial condition,

Table of Contents

Index to Financial Statements

our counterparties have ceased providing the credit necessary to enter into new hedges. Therefore, we may be more exposed to future price fluctuations. We may also be unable to comply with the minimum hedging requirements under the Alta Mesa RBL.

Our policy has been to meet the minimum required hedging levels under the Alta Mesa RBL and to opportunistically hedge an additional portion of our near-term estimated production. Other than the compliance with minimum and maximum hedging levels, our price hedging strategy and future hedging transactions will be determined using Board and management discretion, depending on the financial and future commodity expectations at the time. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged, as compared to current or historic levels, which would result in our oil and gas revenue becoming more sensitive to commodity price fluctuations.

Our use of seismic data is subject to interpretation and may not accurately identify the presence of hydrocarbons, which could adversely affect us.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques help geoscientists in identifying subsurface structures and hydrocarbon indicators, but do not prove the amount, if any, of hydrocarbons present in those structures. The use of seismic data and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, which may result in additional costs without an uplift to a well’s economics. As a result, even our successful drilling activities may not prove economic.

We often gather seismic data surveys over large areas including areas where we own no mineral rights. We may choose not to acquire or pursue mineral interests in areas covered by these surveys, which could result in substantial expenditures to acquire and analyze seismic data without the prospect of future benefit of production.

Competition in our industry is intense, making it more difficult for us to acquire properties, market oil or gas and secure trained personnel.

Our ability to acquire additional properties and pursue our operational objectives is dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive market. Our competitors may be able to pay more for oil and gas properties and pursue a greater number of properties than we can. In addition, our industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has adversely affected the timing and cost of operating. Competition has been historically strong in hiring experienced personnel, particularly in the engineering and technical, accounting, legal and land disciplines. An inability to compete effectively with our competitors could have a material adverse impact on us.

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

Our industry has been characterized by rapid and significant technological advancements and introductions of new products and services using new technologies, all of which could either generate better recoveries or reduce development costs. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and gas companies may be better able to leverage technological advantages. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, it may have a material adverse effect on us.

Deficiencies in title to our leased interests could have a material adverse effect on us.

If an examination of the title history of a property reveals that an oil or gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such cases, the amount paid for such oil or gas lease or leases or other developed rights would be lost. In acquiring mineral rights, we typically choose not to incur the expense of retaining title attorneys, instead we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records before we attempt to acquire a lease or other mineral interest.

Table of Contents

Index to Financial Statements

Prior to drilling a well that we operate, however, we do obtain a preliminary title review of the spacing unit to ensure there are no obvious defects in title to the well. If we do find defects, we must perform or fund curative work to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. We may also elect to proceed with a well despite defects to the title identified in the preliminary title opinion. If we fail to obtain defensible title to our leasehold, we may be unable to develop additional reserves or benefit from the expected ownership.

Our operations are substantially dependent on the availability of water and our inability to obtain water may have a material adverse effect on us.

Water is an essential component of unconventional oil and gas upstream development during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. However, our access to such water supplies may become limited by factors such as extended drought, competition for water or governmental regulation. If we are unable to obtain sufficient amounts of water, our ability to develop our reserves could be restricted or made less economic, which could have a material adverse effect on us.

Litigation and investigations by private plaintiffs or government officials or entities could adversely affect our performance.

Oil and gas upstream and midstream activities are complex and involve risks that could lead to legal proceedings. We currently are defending litigation and anticipate that we will be required to defend new litigation in the future. The subject matter of such litigation may include releases of hazardous substances from our facilities, contract, title or royalty disputes, regulatory compliance matters, personal injury or property damage matters or disputes related to any other laws or regulations that apply to our operations. In some cases, the plaintiff or plaintiffs seek alleged damages involving large classes of potential litigants and may allege damages relating to extended periods of time or other alleged facts and circumstances. For instance, we and certain of our former and current directors and officers were named as defendants in three putative securities class action claims alleging that the defendants disseminated a false and misleading proxy statement in connection with the Business Combination as well as alleged misstatements after the Business Combination. In addition, the SEC is conducting a formal investigation into the facts involved in the material weakness in our internal controls over financial reporting and the impairment disclosed previously and in this Annual Report.

These and other legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that such proceedings could result in liability, penalties or sanctions, judgments, consent decrees, injunctive relief or orders requiring a change in our business practices, which could have a material adverse effect on us. Accruals for such liabilities, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

Our operations are regulated and the costs to comply or a failure to comply could be costly and have a material adverse effect on us.

We may incur significant costs and liabilities as a result of wide-ranging environmental requirements applicable to our operations. Such environmental laws and regulations include the following federal laws (along with their state counterparts):

• the Clean Air Act (“CAA”), which restricts the emission of air pollutants from many sources, imposes various pre-construction, monitoring and reporting requirements and is relied upon by the U.S. Environmental Protection Agency (“EPA”) as authority for adopting climate change regulatory initiatives relating to GHG emissions;

• the Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;

• the Oil Pollution Act (“OPA”), which imposes liabilities for removal costs and damages arising from an oil spill into waters of the United States;

• the Safe Drinking Water Act (“SDWA”), which ensures the quality of the nations’ public drinking water through adoption of drinking water standards and control over the subsurface injection of fluids into belowground formations;

• the Resource Conservation and Recovery Act (“RCRA”), which imposes requirements for the generation, treatment, storage, transport disposal and cleanup of non-hazardous and hazardous wastes;

• the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which imposes liability on generators, transporters and arrangers of hazardous substances sent for disposal to sites where hazardous substance

Table of Contents

Index to Financial Statements

releases have occurred or are threatening to occur, as well as imposes liability on present and certain past owners and operators of sites where hazardous substance releases have occurred or are threatening to occur;

• the Emergency Planning and Community Right to Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees and response departments about toxic chemical uses and inventories;

• the Endangered Species Act (“ESA”), which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas; and

• the National Environmental Policy Act (“NEPA”), which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments or environmental impact statements.

These U.S. laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective actions, the incurrence of capital expenditures, delays in the permitting, development or expansion of projects, and the issuance of orders enjoining some or all of our future operations in a particular area. Certain environmental laws and regulations impose strict joint and several liability, without regard to fault or legality of conduct, for costs required to clean up and restore sites where hazardous substances or other wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, wastes or other materials into the environment. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and more stringent laws and regulations may be adopted in the future. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results.

Changes in the legal and regulatory environment governing our industry, particularly changes in the Oklahoma forced pooling system, could have a material adverse effect on us.

Our business is subject to various forms of extensive government regulation, including laws and regulations concerning the location, spacing and permitting of the wells we drill and the disposal of produced water. Changes in the legal and regulatory environment, particularly any changes to Oklahoma’s forced pooling procedures could result in increased compliance costs and adversely affect us.

In the past we have used, and we expect to continue to use, Oklahoma’s forced pooling process to increase our working interest in sections we propose to drill. In recent years, a relatively low percentage of working interest owners in our operated sections have elected to participate in our wells. Due to the continuing consolidation in the STACK by producers with greater access to capital, other working interest owners may be more likely to participate in the wells we drill. Thus, our ability to use forced pooling to increase our working interest may be more difficult to accomplish.

The adoption of derivatives legislation and regulations could have an adverse impact on our ability to hedge risks associated with our business.

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the SEC and the Commodity Futures Trading Commission (the “CFTC”) to enact further regulations affecting derivatives, including those we use to hedge our commodity exposure. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.

In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on December 5, 2016 a re-proposed rule imposing position limits for certain futures and option contracts in various commodities (including gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued.

Table of Contents

Index to Financial Statements

Similarly, on December 2, 2016, the CFTC re-issued a proposed rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, but the CFTC has not yet issued a final rule.

The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. The Dodd-Frank Act also imposes record keeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

All of the above regulations could increase the costs to us of entering into derivatives to hedge or mitigate our commodity price exposure. While we cannot predict when the CFTC will issue final rules applicable to position limits or capital requirements, it may require time and effort for us to comply with position limits and with certain clearing and trade-execution requirements in connection with our derivative activities. When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our counterparties to post additional capital, which could increase the costs of future derivatives. In addition, other provisions of the Dodd-Frank Act could cause current counterparties to restructure their derivative activities, including the potential that they might cease engaging in the business of commodity derivatives.

If we voluntarily or involuntarily reduce our use of derivative contracts as a result of the new requirements, we become more exposed to commodity price fluctuations, which could adversely affect our ability to conduct our operations.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our Upstream operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and gas we may produce and sell.

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil and gas, and incur costs to comply with such federal, state and local laws and regulations.

Under the Natural Gas Act (“NGA”), the Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation and sale for resale of gas, as well as the construction and operation of interstate gas pipelines. As a general matter, states regulate the intrastate transportation, local distribution and retail sale of gas under state laws and regulations.

Under the Interstate Commerce Act (“ICA”), FERC also regulates the rates and practices of oil pipeline companies engaged in interstate transportation, establishes equal service conditions to provide shippers with equal access to oil pipeline transportation, and establishes reasonable rates for transporting petroleum and petroleum products by pipeline.

The U.S. Congress, FERC, state legislatures and regulatory commissions and courts often consider legislative and regulatory proposals and proceedings that could affect the gas and oil industry. The industry historically has been heavily regulated and we cannot predict future legislative and regulatory proposals and proceedings or what effect such proposals or proceedings may have on our operations. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenue, our financial condition would be adversely affected.

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

Table of Contents

Index to Financial Statements

Should we fail to comply with all applicable statutes, rules, regulations and orders administered by the FERC or CFTC, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005 (“EPAct”), FERC has civil penalty authority under the NGA, including the ability to impose penalties of up to $1 million per day for each violation and disgorgement of profits associated with any violation of the NGA or FERC’s regulations under the NGA. We do not currently operate any FERC-regulated assets nor are we or our subsidiaries regulated by FERC as "natural gas companies" under the NGA. However, as a customer of gas transportation service, we must comply with the terms and conditions of FERC-jurisdictional tariffs pursuant to which transportation service is provided and the anti-market manipulation rules enforced by FERC under the NGA. If we fail to comply with all the applicable FERC-administered statues, rules, regulations and orders, we could be subject to substantial penalties. FERC also has the power to order disgorgement of profits from transactions deemed to violate the NGA.

Under the Commodity Exchange Act (as amended by the Dodd-Frank Act) and regulations promulgated thereunder by the CFTC, the CFTC has also adopted anti-market manipulation, fraud and market disruption rules relating to the prices of commodities, futures contracts, options on futures, and swaps. Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, FERC, or the CFTC from time to time. Failure to comply with those statutes, regulations, rules and orders could subject us to civil penalty liability.

Climate change legislation or other regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and gas we produce.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and may continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations under the CAA that, among other things, establish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential sources of significant pollutant emissions. Sources subject to these permitting requirements must meet “best available control technology” standards for those GHG emissions. Additionally, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including, among others, onshore and offshore oil and gas production, processing, transmission, storage and distribution facilities, which include certain of our operations.

Federal agencies also directly regulate emissions of methane, a GHG, from oil and gas operations. In August 2016, the EPA issued a final NSPS rule, known as Subpart OOOOa, that requires certain new, modified or reconstructed facilities in the oil and gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices. On September 11, 2018, however, the EPA proposed changes to the August 2016 final NSPS rule applicable to oil and gas well vapor leaks. These changes, if implemented, would ease compliance obligations by decreasing fugitive emission monitoring frequency requirements, allowing more time for repairs, and allowing compliance with certain state regulations in lieu of complying with federal regulations. Moreover, on March 2, 2017 the EPA withdrew a previously issued Information Collection Request that sought information about methane emissions from facilities and operations in the oil and gas industry.

In December 2015, the United States attended the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. At the Conference, an agreement was prepared that requires member countries to determine, plan, and regularly report on their contribution to the mitigation of global warming. Under the agreement, GHG emission reduction goals are established every five years beginning in 2020. The agreement does not create any binding obligations for countries to limit their GHG emissions but, rather, includes pledges to voluntarily limit or reduce future emissions. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016. On June 1, 2017, President Trump announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain, and the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement, if it chooses to do so, are unclear at this time.

Table of Contents

Index to Financial Statements

The adoption and implementation of any international treaty, or federal or state legislation, regulations or other regulatory initiative that imposes a carbon tax, requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, that could have an adverse effect on our business, financial condition and results of operations. Moreover, any such new treaty, legislation, regulation or initiative could increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and gas we produce and lower the value of our reserves.

Finally, it should be noted that some sources estimate that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If such effects were to occur, our development and production operations could be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities because of climate related damages to our facilities, less efficient or non-routine operating practices necessitated by such climate effects, or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations. Nor, are we (on our own) capable of doing this in a prudent and accurate manner that would best serve our investors’ interests. A number of investors have decided not to invest in hydrocarbon producers, which could have an adverse effect on our future cost of capital.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could increase our costs of doing business, impose additional operating restrictions or delays and adversely affect our production.

Hydraulic fracturing is an essential and common practice we use to develop our reserves. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation to fracture the surrounding rock and stimulate production. We routinely apply hydraulic fracturing techniques to stimulate production from the wells we drill.

Our hydraulic fracturing technique is currently generally exempt from regulation under the SDWA’s Underground Injection Control (“UIC”) program and is typically regulated by the Oklahoma Corporation Commission. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. In June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants and, in 2014, the EPA asserted regulatory authority pursuant to the UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Also, in 2015, the Bureau of Land Management (“BLM”) published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands. On December 29, 2017, BLM rescinded the 2015 rule. California and certain environmental groups have sued over the BLM’s rescission of the 2015 rule.

Additionally, in 2014, the EPA published an advanced notice of public rule making regarding Toxic Substances Control Act (“TSCA”) reporting of the chemical substances and mixture used in hydraulic fracturing. From time to time, Congress has introduced, but not adopted, legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of chemicals used in the fracturing process.

In addition, some states, including Oklahoma, have adopted, regulations that restrict or could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. Concerns have been raised that hydraulic fracturing activities may be correlated to anomalous seismic events. In December 2016, the OCC Oil and Gas Conservation Division and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. States could elect to prohibit high-volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular, although

Table of Contents

Index to Financial Statements

Oklahoma has taken steps to limit the authority of local governments to regulate oil and gas development. The issuance of any laws, regulations or other regulatory initiatives that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to develop our reserves or conduct our operations, either one of which could have a material adverse effect on us.

Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to dispose of produced water gathered from our drilling and production activities, which could have a material adverse effect on our business.

We dispose of produced water gathered from our operations pursuant to permits issued to our affiliates or third-party vendors by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent permitting or operating constraints or new monitoring and reporting requirements owing to, among other things, concerns of the public or governmental authorities regarding such disposal activities.

One such concern relates to recent seismic events near underground injection wells used for the disposal of produced water resulting from oil and gas activities. When caused by human activity, such events are called induced seismicity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, where we operate. In response to these concerns regarding induced seismicity, regulators in some states, including Oklahoma, have imposed, and other states are considering imposing, additional requirements in the permitting of produced water injection wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for injection wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on injection wells in proximity to faults and also, from time to time, developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend injection well operations. The Oklahoma Corporation Commission (“OCC”) has implemented the National Academy of Science’s “traffic light system,” in determining whether new injection wells should be permitted, permitted only with special restrictions, or not permitted at all. In addition, the OCC has established rules requiring operators of certain produced water injection wells in seismically-active areas, or Areas of Interest, within the Arbuckle formation of the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC from time to time has developed and implemented plans calling for injection wells within Areas of Interest where seismic incidents have occurred to restrict or suspend disposal operations in an attempt to mitigate the occurrence of such incidents. In February 2017, the OCC’s Oil and Gas Conservation District issued an order limiting future increases in the volume of oil and gas wastewater injected below ground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state.

Also, ongoing lawsuits allege that injection well disposal operations have caused damage to neighboring properties or otherwise violated state and federal rules governing waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells. Increased regulation and attention given to induced seismicity could lead to greater opposition, including litigation, to oil and gas activities utilizing injection wells for produced water disposal. Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of produced water into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where produced water injection activities occur or are proposed to be performed. Court decisions or the adoption of any new laws, regulations or directives that restrict our ability to dispose of produced water generated by production and development activities, whether by plugging back the depths of disposal wells, reducing the volume of produced water disposed in such wells, restricting injection well locations or otherwise or by requiring us to shut down injection wells, could significantly increase our costs to manage and dispose of this produced water, which could have a material adverse effect on our financial condition and results of operations.

Laws and regulations pertaining to threatened and endangered species or protective of environmentally sensitive areas could delay or restrict our operations and cause us to incur significant costs.

Our operations may be adversely affected by seasonal or permanent restrictions or costly mitigation measures imposed under various federal and state statutes in order to protect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. Federal statutes, as amended from time to time, that are protective of these species, birds and environmentally sensitive areas include the ESA, the Migratory Bird Treaty Act (the “MBTA”), the CWA, the CERCLA and the OPA. For example, to the extent that species are listed under the ESA or similar state laws and live in areas where our oil and gas upstream activities are conducted, our ability to conduct or expand operations and construct facilities could be limited or we

Table of Contents

Index to Financial Statements

could be forced to incur material additional costs. Moreover, our operations may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.

Additionally, the U.S. Fish and Wildlife Service (“FWS”) may designate new or increased critical habitat areas that it believes are necessary for survival of threatened or endangered species, which designation could result in material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development. As a result of one or more settlements approved by the federal government, the FWS must make determinations on the listing of numerous specified species as endangered or threatened under the ESA pursuant to specified timelines. The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. If harm to protected species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and, in some cases, may seek criminal penalties. The designation of previously unprotected species as threatened or endangered in areas where we conduct operations could cause us to incur increased costs arising from species protection measures or time delays or limitations on our operations.

We could experience periods of higher costs if oil and gas prices rise or as drilling activity otherwise increases in the STACK, which could reduce our ability to develop our reserves and otherwise have a material adverse effect on us.

Historically, our capital and operating costs typically rise during periods of sustained increasing oil, gas and NGL prices. These cost increases result from a variety of factors beyond our control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that we and our vendors rely upon; and the cost of services and labor, especially those required in horizontal drilling and completion. As commodity prices rise or drilling activity otherwise increases in the STACK, our costs for materials, services and labor may increase, which may negatively impact our profitability, cash flow and cause us to delay, reduce or curtail our drilling program.

The sale of our production is dependent upon midstream and downstream facilities over which we may have no control.

The marketability of our production depends upon the availability, proximity and capacity of facilities and services, including pipelines, natural gas gathering systems, trucking or terminal facilities and processing facilities. We deliver oil, gas and NGLs through gathering systems and pipelines that we do not necessarily own. The lack of available capacity on these systems and facilities could impact us by causing our production to be shut-in, reducing the price we receive for our production or delaying or eliminating our future development plans. Although we have some contractual control over this third-party-operated risk by virtue of the underlying contracts, such systems and facilities may be temporarily unavailable due to market conditions or operational reasons. Further, in the future, these systems and facilities may not be available to us at a price that is acceptable to us. Any significant change in market factors or other conditions affecting these systems and facilities, as well as any delays in constructing new systems and facilities, could have a material adverse effect on us.

Our Upstream business relies primarily on KFM for gathering, transportation, processing and produced water disposal services.

Our oil and gas production, not otherwise previously dedicated, is dedicated to KFM. Also, in November 2018, Alta Mesa sold its produced water assets to a subsidiary of KFM. In conjunction with the sale, Alta Mesa entered into a new 15-year water gathering and disposal agreement with KFM’s subsidiary. As a result, our Upstream business is substantially dependent upon KFM for its oil, NGL, gas and produced water-related operations. If KFM were unable to continue to provide these services, it could result in the shut-in of our production or cause delays and additional costs to find alternate providers for those services, any one of which could have a material adverse effect on us.

The parties on whom we rely for gathering, transportation and processing services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

Gathering, transportation and processing operations are subject to complex laws and regulations that require parties providing these services to obtain and maintain numerous permits, approvals and certifications with various levels of government. These operations could require substantial costs in order to comply with existing laws and regulations. If laws and regulations governing such operations are enacted, revised or reinterpreted, these changes may affect the costs that we pay for such

Table of Contents

Index to Financial Statements

services. There could be a material adverse effect on us if the gathering, transportation and processing operations that we rely upon were materially impacted by those laws and regulations.

We have limited control over activities on properties we do not operate, which could reduce our production and revenue.

We have limited control over properties that we do not operate, including a limited ability to influence normal operating procedures, expenditures or future development of the underlying properties. The failure of another operator to adequately perform operations or that operator’s financial difficulties could reduce our production and revenue. The success and timing of our drilling and development activities on properties operated by others, depends upon a number of factors outside of our control, including the operator’s timing of development and amount of capital expenditures, expertise and financial resources.

Turnover of our key executives and Board of Directors and difficulty of recruiting and retaining key employees could have a material adverse impact on our business.

We experienced a significant amount of executive-level turnover in late 2018. In early 2019, we introduced a new executive team including an Interim President, an Interim Chief Operating Officer and a Chief Financial Officer. Our inability to retain the new management team and our remaining key executives and employees could harm our business and operations and have a material adverse effect on us.

Our success will depend to a large extent upon the efforts and abilities of our management team and having experienced individuals serving on our Board who are also knowledgeable about our operations and our industry. We may be unable to timely replace the talents and skills of our management team or directors if one or more did not continue serving. Our business also depends upon our ability to attract and retain qualified personnel. If we are unable to retain or find replacement employees, the loss of the services of one or more of these key employees could have a material adverse effect on us. We do not maintain key-man life insurance with respect to any of our employees. Acquiring and keeping personnel could prove more difficult or cost substantially more than estimated. These factors could cause us to incur greater costs or prevent us from pursuing our development and exploitation strategy as quickly as we would otherwise wish to do.

We operate in an area of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.

Oil and gas development in the STACK has been quite active in recent years. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, increased over the past few years and may increase again in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. Any delay or inability to secure the personnel necessary for us to conduct our planned development activities could result in our production falling below our forecasted volumes, which could have a material adverse effect on us at our estimated production levels in the next several years.

We may encounter obstacles marketing our oil and gas which could adversely impact our revenue.

The marketability of our production will depend in part upon the availability of purchasers in our area plus gathering systems and pipelines owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities, but since we hold firm transportation covering our current level of gas production we do not believe a significant risk exists that other companies would hold priority over us in the near term.

The availability of markets is beyond our control. If market factors dramatically change, our revenue could be substantially impacted, which could have a material adverse effect on us.

We have identified material weakness in our internal control over financial reporting which, if not corrected, could affect the reliability of our financial statements, increase our costs and efforts to ensure accurate reporting and have other adverse consequences.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (ICFR). Section 404 of SOX requires management to assess the effectiveness of our ICFR. Based on our assessment as of December 31, 2018, we concluded that our ICFR was not effective as of that date, due to identification of material weakness. A material weakness is a deficiency or combination of deficiencies in ICFR that causes a reasonable possibility that a material

Table of Contents

Index to Financial Statements

misstatement could occur and not be prevented or detected on a timely basis. Our material weakness relates to both the design of our controls and execution of control procedures. Item 9A contains additional information regarding our deficiencies and the proposed remediation plan.

If not remediated, the material weaknesses could result in a material misstatement to our annual or interim consolidated financial statements that would not be prevented or detected on a timely basis. Our management has developed, and begun to implement, a plan to remediate the material weaknesses. We may not be able to implement the plan, or to remediate the material weaknesses in a timely manner. In addition, we may require more than one year to effect a system of internal controls and an information technology environment that are sufficiently designed and properly executed to prevent material misstatements from going undetected. Furthermore, during the course of re-designing existing processes and controls, implementing additional processes and controls and testing of the operating effectiveness of such re-designed and additional processes and controls, we may identify additional control deficiencies that could give rise to other material weakness, in addition to the currently identified matters. If we are unable to remediate our material weakness, or if additional material weakness or deficiency is discovered, we may be unable to report our financial results accurately or timely, which could cause our reported financial results to be materially misstated, which could adversely affect the market price of our securities and our ability to access the capital markets. Furthermore, the effort to remediate our internal controls could be expensive or could distract management from managing the business, either of which could adversely affect us.

There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected.

We do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the resource constraints and the benefit of controls relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our Company have been detected. These inherent limitations reflect that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.

Our business and operations could be negatively impacted by shareholder activism, which could cause us to incur significant expense, hinder execution of our business strategy and impact our stock price.

Shareholder activism, which could take many forms and arise in a variety of situations, could result in substantial costs and divert management’s and our Board’s attention and resources from our business. Additionally, such shareholder activism could give rise to perceived uncertainties as to our future, adversely affect our relationships with service providers and make it more difficult to attract and retain qualified personnel. Also, we may be required to incur significant legal fees and other expenses related to activist shareholder matters. Our stock price could be subject to significant fluctuation or otherwise be adversely affected by the events, risks and uncertainties of any shareholder activism.

Cyber-attacks targeting systems and infrastructure may adversely impact our operations.

Our industry has become increasingly dependent on digital technologies to conduct day-to-day operations. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, conduct reservoir modeling and for compliance reporting. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as power generation and transmission, communications and oil and gas pipelines.

We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves as well as other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production, and financial institutions, are also

Table of Contents

Index to Financial Statements

dependent on digital technology. The technologies needed to conduct oil and gas exploration and development activities and global competition for oil and gas resources make certain information the target of theft or misappropriation.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also have increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-based systems are potentially vulnerable to targeted cyber-attacks due to their critical role in operations.

Our systems and networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of information, or cause other disruptions to our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:

• unauthorized access to seismic data, reserves information, royalty owner data or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;

• data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;

• data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;

• a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt a development project, effectively delaying the start of cash flows from the project;

• a cyber-attack on a third party gathering or pipeline service provider could prevent us from marketing our production, resulting in a loss of revenue;

• a cyber-attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenue;

• a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenue;

• a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and

• expensive remediation efforts, distraction of management or damage to our reputation.

Our implementation of various controls and processes, including globally incorporating a risk-based cyber security framework, to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

Certain U.S. federal income tax preferences could be eliminated as a result of future legislation.

There has been proposed legislation that would, if enacted, make significant changes to U.S. tax laws regarding provisions currently available to oil and gas companies. Such legislative changes have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas upstream development. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in our industry. These changes include:

• the repeal of the percentage depletion allowance;

• the elimination of current deductions for intangible drilling costs; and

• the increase in the amortization period from two years to seven years for geophysical costs.

It is unclear whether any such changes will be enacted or proposed by current or future administrations or how soon any such changes would become effective. In addition, Congress passed tax reform in December of 2017, and that legislation has changes including, but not limited to:

• the elimination of the deduction for U.S. production activities;

Table of Contents

Index to Financial Statements

• the provision for individual taxpayers to deduct 20% of their domestic qualified business income (which may provide some relief from the aforementioned item);

• more stringent limitation on business interest deduction;

• modification of NOL carryforward rules; and

• changes to items excluded from the $1.0 million executive compensation deduction limitation.

The further passage of any legislation, including the proposals above, or changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.

Risks Related to Our Indebtedness

We have substantial indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

Our present level of indebtedness requires us to use a substantial portion of our cash flow to pay interest, which reduces funds available to finance our capital and acquisition activities and could limit our flexibility in reacting to changes in our business. The outstanding debt under both the Alta Mesa RBL and KFM Credit Facility bears interest at a variable rate, and so a rise in interest rates will generate greater interest expense (provided we have not hedged against interest rate increases). The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.

We may incur substantially more debt in the future. The indenture governing our outstanding 2024 Notes contains restrictions on our incurrence of additional indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness and remain in compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring obligations that do not constitute “indebtedness” as defined under the indenture.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If cash flow is not sufficient to service debt, we may be required to refinance debt, sell assets or sell additional securities on terms that we may not find attractive if it may be done at all. Further, the failure to comply with the financial and other restrictive covenants relating to the indebtedness could result in a default under that indebtedness, which could have a material adverse affect on us.

Our significant indebtedness could give rise to other material adverse consequences, including the following:

• the Alta Mesa RBL and the indenture governing the 2024 Notes have cross default provisions, which could result in the acceleration of indebtedness under both agreements if we fail to comply with the covenants and other provisions in either agreement;

• it may be difficult to satisfy our obligations, including debt service requirements under debt agreements, or maintain compliance with financial and other debt covenants;

• we might be unable to fund operations, working capital, capital expenditures, debt service requirements and other general corporate needs;

• a significant portion of our cash flow is committed to payments on our debt, which will reduce the funds available to us for other purposes, such as future capital expenditures, acquisitions and general working capital;

• we are more vulnerable to price fluctuations and to economic downturns and adverse industry conditions and our flexibility to plan for, or react to, changes in our business or industry is more limited; and

• our ability to capitalize on business opportunities and to react to competitive pressures may be limited.

The Alta Mesa RBL and the indenture governing Alta Mesa’s 2024 Notes have restrictive covenants that could limit its growth, financial flexibility and its ability to engage in certain activities. Since Alta Mesa is our subsidiary, most of the effects apply to us.

The Alta Mesa RBL and the indenture governing Alta Mesa’s 2024 Notes have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in activities that may be in our long-term best interests. These covenants, among other things, limit our ability to:

• incur additional indebtedness;

• sell assets;

• guaranty or make loans to others;

Table of Contents

Index to Financial Statements

• make investments;

• enter into mergers;

• make certain payments and distributions;

• enter into or be party to hedge agreements;

• amend our organizational documents;

• incur liens; and

• engage in certain other transactions without the prior consent of our lenders.

In addition, the Alta Mesa RBL requires Alta Mesa to maintain financial ratios or to reduce its indebtedness if it is unable to comply with such ratios, which may limit its ability to obtain future financings to withstand a future downturn in its business or the economy in general or to otherwise conduct necessary corporate activities. Alta Mesa may also be prevented from taking advantage of business opportunities that arise because of these limitations.

Any significant reduction to the Alta Mesa RBL borrowing base as a result of the periodic redeterminations or other reasons may negatively impact our ability to fund our operations and we may not have sufficient funds to repay borrowings under the Alta Mesa RBL, if required as a result of a borrowing base redetermination.

Availability under the Alta Mesa RBL was subject to a borrowing base of $400.0 million at December 31, 2018. The borrowing base is subject to at least semi-annual redeterminations that are based on the value of Alta Mesa’s oil and gas reserves as determined by the Alta Mesa RBL lenders and other factors deemed relevant by the lenders. On April 1, 2019, the borrowing base was reduced to $370.0 million upon completion of the regularly scheduled semi-annual redetermination. Substantially all of the available borrowing base is currently utilized. In August 2019, the lenders exercised their option to conduct an optional redetermination, pursuant to which they established a revised borrowing base of $200.0 million, which will require us to make monthly installments of $32.5 million for five months beginning in September 2019. As a consequence of reduced operating cash flow and a lowered borrowing base, we have limited ability to obtain the capital necessary to conduct our operations at desired levels. Additionally, if we are in default under the Alta Mesa RBL, the lenders could cease making amounts available, accelerate payment of amounts outstanding or seek other remedies any of which would further limit our access to the capital necessary to fund our capital expenditures. Declines in oil and gas prices or a decrease in reserves for any reason, including the removal of our PUDs in April 2019, could cause the Alta Mesa RBL banks to reduce the borrowing base as part of future redeterminations. Any significant future reduction in our borrowing base could have a material negative impact on our liquidity and our ability to fund our operations. Further, if the outstanding borrowings under the Alta Mesa RBL were to exceed the borrowing base due to any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may be in default under the Alta Mesa RBL, which could have a material adverse effect on us.

If we are unable to comply with the restrictions and covenants in our debt agreements, we could default under the terms of such agreements, which could ultimately result in an acceleration of repayment.

If we cannot comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of these agreements. Our ability to comply with these restrictions and covenants, including meeting financial ratios and tests, may be affected by events beyond our control. As a result, we cannot provide assurance that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. Although certain types of circumstances (such as delays in providing timely financial information) give rise to defaults that are curable under the agreements, we may not be able to cure all defaults within the cure period, which could give rise to an event of default and potentially an acceleration of amounts due. Moreover, if we are in default on any indebtedness, we would be unable to make borrowings under the Alta Mesa RBL or the KFM Credit Facility even if there are remaining borrowings available thereunder.

If we are unable to generate sufficient cash flow or are otherwise unable meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants in the instruments governing our indebtedness, we could be in default under those agreements. During 2019, we may be unable to satisfy the consolidated total leverage ratio in the Alta Mesa RBL and recognize the need to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, the lenders under the Alta Mesa RBL could terminate their commitments to lend, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy protection. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions, such as the indenture governing Alta Mesa’s 2024 Notes, may also be accelerated and become due and payable. If any of these events occur, our assets might not be sufficient to repay in

Table of Contents

Index to Financial Statements

full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our debt agreements or obtain needed waivers on satisfactory terms.

To service our indebtedness, we require significant liquidity and our ability to generate cash depends on many factors beyond our control.

Our ability to service and refinance our debt and to fund planned capital expenditures depends on our generating cash. This ability hinges on general economic, financial, competitive, legislative, regulatory and other factors beyond our control. We can provide no assurance that we will generate sufficient operating cash flow, that we will realize the planned operating cost improvements or that future borrowings will be available to us in an amount sufficient to service and repay our debt, while still funding our other liquidity needs. If we are unable to satisfy our debt obligations, we may have to undertake alternative plans such as:

• refinancing or restructuring our debt;

• selling assets;

• reducing or delaying capital investments; or

• seeking to raise additional capital.

Any alternative plans that we undertake may still not enable us to meet our debt obligations. We can provide no assurance that any refinancing or debt restructuring would be possible, that any assets could be sold or that, if sold, the timing of the sales and proceeds realized from those sales would be favorable or that additional financing could be obtained on acceptable terms. Our inability to generate sufficient cash flows to satisfy our debt or to obtain alternative financing could have a material adverse effect on us and could result in us being unable to continue as a going concern.

Restrictions in KFM’s Credit Facility could adversely affect its financial condition, results of operations or cash flows. Since KFM is our subsidiary, most of the effects of these debt facilities on KFM apply equally to us.

KFM is a party to a $300.0 million credit agreement that matures on May 30, 2023, with quarterly interest payments due on Base Rate loans. KFM’s interest rates depend upon its consolidated leverage ratio and KFM can elect to borrow on a Eurodollar Loan or Base Rate Loan basis. Both the Eurodollar Loan and Base Rate Loan margins are subject to minimum rates established by third-party institutions, such as, but not limited to the Federal Reserve. The terms of this credit agreement limit KFM’s ability to, among other things:

• incur or guarantee additional debt;

• make certain investments and acquisitions;

• incur certain liens or permit them to exist;

• enter into certain types of transactions with affiliates;

• merge or consolidate with another company; and

• transfer, sell or otherwise dispose of assets.

The KFM Credit Facility also contains covenants requiring it to maintain certain financial ratios. KFM’s ability to meet those financial ratios and tests can be affected by events beyond its control, and KFM cannot assure that it will meet any such ratios and tests.

The provisions of the KFM Credit Facility may affect its ability to obtain future financing and pursue attractive business opportunities and its flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the credit facility could result in a default or an event of default that could enable KFM’s lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of KFM’s debt is accelerated, its assets may be insufficient to repay such debt in full.

If High Mesa Inc. and its subsidiaries (collectively, “HMI”) default on their obligations to us, it could have a material adverse effect on us and our results of operations, and could cause a default under the Alta Mesa RBL and could adversely impact the trading price for our securities.

High Mesa Services LLC (“HMS”), a subsidiary of HMI, is the promissor under two promissory notes in the principal amount of $1.5 million and $8.5 million. As of December 31, 2018, approximately $1.7 million and $11.7 million, respectively, were

Table of Contents

Index to Financial Statements

outstanding under the promissory notes including the accumulated interest cost. The promissory notes became the property of the Company pursuant to the identification of acquired assets under the Business Combination. When the $1.5 million promissory note became due on February 28, 2019, HMS made no payment and therefore defaulted under its terms, and HMS has failed to cure such default. Following the default, we submitted a demand letter to preserve our rights, declaring all amounts owing under the $1.5 million note immediately due and payable. HMI disputes that it has any obligation to pay the $1.5 million promissory note and the $8.5 million promissory note to us. We are pursuing remedies in connection with securing repayment of the past due promissory note by HMS and the $8.5 million promissory note, which matures on December 31, 2019, but there is no guarantee that we will be successful in securing such repayment in full, or in part, or that HMI will have the liquidity necessary to repay the notes.

Pursuant to the Business Combination, we distributed our non-STACK oil and gas assets to a subsidiary of HMI, and certain subsidiaries of HMI agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. We also entered into a management services agreement (the “MSA”) with HMI whereby we agreed to provide management services to HMI with respect to the non-STACK oil and gas assets, which included both operational and administrative functions. At December 31, 2018, HMI owed us approximately $10.0 million, which includes amounts owed (i) under the MSA, (ii) from a duplicate revenue payment made to HMI and (iii) pursuant to payables arising prior to the Business Combination. Subsequent to year-end, we billed HMI an additional $0.9 million for incremental MSA costs incurred and have received approximately $1.0 million in payments toward all amounts outstanding. HMI has disputed certain of these amounts. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result, we have recognized an allowance for uncollectible accounts of $9.0 million to fully provide for the un-remitted balance and may have future allowances for amounts incurred in 2019 prior to the termination of the MSA. We also may be subject to liabilities for the non-STACK assets for which we should be indemnified, including liabilities associated with litigation relating to the non-STACK assets.

Under the Alta Mesa RBL, Investments (as defined) are limited to $10.0 million. If the amounts due from HMI continue unpaid, they may be deemed Investments, which when aggregated with other Investments could cause Alta Mesa to be in default under the Alta Mesa RBL. Such default would require us to get a waiver or other relief from our lenders. If we are unable to get such relief, the lenders may exercise their rights under the agreement, which as described elsewhere in our Risk Factors, could include acceleration of amounts due. A failure by HMI to pay its obligations to us could also have an adverse impact on our financial position and results of operations. Alternatively, if HMI, which holds an estimated 134.0 million shares of our Class C Common Stock, sells all or a portion of those shares to fulfill its obligations under the MSA, the trading price of our shares may be negatively affected.

Additionally, we are co-guarantors under certain surety bonds with HMI, including bonds that cover the non-STACK oil and gas assets owned by them. The surety has requested posting of collateral. If HMI cannot post collateral or satisfy its indemnity obligations, Alta Mesa may be required to post collateral or otherwise satisfy HMI’s obligations associated with HMI surety bonds in an amount of approximately $15 million.

Risks Related to our Midstream Business

We must continually compete for crude oil, gas and produced water supplies, and any decrease in supplies of such commodities could adversely affect our financial condition, results of operations or cash flows.

In order to maintain or increase throughput levels in our gathering system and asset utilization rates at our processing plant, we must continually contract for new product supplies. We may not be able to obtain additional contracts for crude oil and gas and NGL supplies. The primary factors affecting our ability to connect new wells to our gathering facilities include our success in contracting for existing supplies that are not committed to other systems and the level of drilling activity near our gathering system. If we are unable to maintain or increase the volumes on our system by accessing new supplies to offset the natural decline in reserves, our business and financial results could be adversely affected. In addition, our future growth will depend in part upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our current supplies.

Any decrease in the volumes that we gather, process, store or transport would adversely affect our financial condition, results of operations or cash flows.

Table of Contents

Index to Financial Statements

Our financial performance depends to a large extent on the volumes of crude oil, gas and produced water gathered, processed, stored and transported on our assets. Decreases in the volumes of crude oil, gas and produced water we gather, process, store or transport would directly and adversely affect our financial condition, results of operations or cash flows. These volumes can be influenced by factors beyond our control, including:

• environmental or other governmental regulations, including changes in tax policy;

• weather conditions;

• increases in storage levels of crude oil, gas and produced water;

• increased use of alternative energy sources;

• decreased demand for crude oil, gas and produced water;

• continued fluctuation in commodity prices, including the prices of crude oil, gas and produced water;

• economic conditions;

• supply disruptions;

• availability of supply connected to our systems; and

• availability and adequacy of infrastructure to gather and process supply into and out of our systems.

The volumes of crude oil, gas and produced water gathered, processed and transported on our assets also depend on the production from the region that supplies our systems. Supply of crude oil, gas and produced water can be affected by many of the factors listed above, including commodity prices and weather. For instance, during 2018, we saw reduced drilling activity due to lower commodity prices and changes to the drilling plans of the operators with acreage dedicated to KFM, and we were unable to secure volumes from our Upstream business and third parties at levels we were projecting. Because we are substantially dependent on our Upstream business for a significant portion of our throughput, the reduced Upstream 2019 drilling program and any subsequent reductions in that program could significantly lower future volumes on the system if we are unable to find third-party customers.

In order to maintain or increase throughput levels on our system, we must obtain new sources of crude oil, gas and produced water. The primary factors affecting our ability to obtain non-dedicated sources of crude oil, gas, and produced water include (i) the level of successful leasing, permitting and drilling activity in our areas of operation, (ii) our ability to compete for volumes from new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines. We anticipate that the reduced 2019 drilling program of our Upstream business may affect the production supply levels on our system. Additionally, we have no control over the level of drilling activity of third parties in our area of operation, the amount of reserves associated with wells connected to our system or the rate at which production declines from a well. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, levels of reserves, availability of drilling rigs and other costs of production and equipment.

Construction of certain midstream assets subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations or cash flows.

The construction of midstream assets is complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, complying with laws, unavailability of materials, construction delays, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these midstream assets could adversely affect our financial condition, results of operations or cash flows. The construction of pipelines and gathering and processing and storage facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and capital position could be adversely affected. This level of development activity requires significant effort from our management and technical personnel. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.

Our construction of new assets may be more expensive than anticipated and may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks that could adversely affect our financial condition, results of operations or cash flows.

The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control including potential protests or legal actions by interested third parties that may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them on

Table of Contents

Index to Financial Statements

schedule, at the budgeted cost or at all. Moreover, our revenue may not increase due to the successful construction of a particular project. For instance, if we expand a pipeline or construct a new pipeline, the construction may occur over an extended period of time, and we may not receive any material increases in revenue promptly following completion of a project or at all. Further, we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our financial condition, results of operations or cash flows. In addition, the construction of additions to our existing gathering and processing assets will generally require us to obtain new rights-of-way and permits prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way or permits to connect new product supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

We may be unable to obtain or renew permits necessary for our operations which could inhibit our ability to do business.

Performance of our operations requires that we obtain and maintain a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay the issuance of a new or existing material permit or other approval, or to revoke or substantially modify an existing permit or other approval, could adversely affect our ability to initiate or continue operations at the affected location or facility, our financial condition, results of operations and cash flows.

Additionally, in order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time required to prepare applications and to receive authorizations.

We typically do not obtain independent evaluations of hydrocarbon reserves; therefore, volumes we service in the future could be less than anticipated.

We typically do not obtain, on a regular basis, independent evaluations of hydrocarbon reserves connected to our gathering systems or that we otherwise service due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, other than reserve estimates with respect to our Upstream business, we do not have independent estimates of total reserves serviced by our assets or the anticipated life of such reserves. If the total reserves or estimated life of the reserves is less than we anticipate and we are unable to secure additional sources, then the volumes we gather and process could be lower, which would adversely affect our financial condition, results of operations or cash flows.

Our exposure to commodity price risk may change over time.

We generate substantially all of our revenue from our Midstream business pursuant to fee-based contracts under which we are paid based on the volumes that we gather, process and transport, rather than the underlying value of the commodity, in order to minimize our exposure to commodity price risk. However, we are a party to fee-based contracts that have a small portion of percent-of-proceeds contractual mix, but the portion of percent-of-proceeds does not exceed 6.0% for any one contract. In addition, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of crude oil, gas and NGL prices could adversely affect our financial condition, results of operations or cash flows. Also, as with any acreage dedications, the profitability of those dedications depends on drilling activity that is often influenced by the behavior of commodity prices.

If third-party pipelines or other midstream facilities interconnected to our gathering, processing, storage or transportation systems become partially or fully unavailable, or if the volumes we gather, process, store or transport do not meet the quality requirements of the pipelines or facilities to which we connect, our gross profit and cash flow could be adversely affected.

Our Midstream assets connect to pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of, and our continuing access to, such third-party pipelines and other facilities is not within our control. These

Table of Contents

Index to Financial Statements

pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if our costs to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurs, or if we lose access to these pipelines or other midstream facilities, or if the volumes we gather or transport do not meet their product quality requirements, our gross profit and cash flows could be adversely affected.

The midstream industry is highly competitive, and increased competitive pressure could adversely affect our financial condition, results of operations or cash flows.

We compete with similar midstream enterprises in our area of operation. The principal elements of competition are rates, terms of service and flexibility and reliability of service. Our competitors include large crude oil and gas companies that have greater financial resources and access to supplies of crude oil, gas and produced water than us. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services we provide to our customers. Excess pipeline capacity in the region served by our intrastate pipelines could also increase competition and adversely impact our ability to renew or enter into new contracts with respect to our available capacity when existing contracts expire. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain or increase current revenue and cash flows could be adversely affected by the activities of our competitors and customers. Further, gas utilized as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of gas could lead to a reduction in demand for gas gathering, processing, storage and transportation services. All of these competitive pressures could adversely affect our financial condition, results of operations or cash flows.

If we do not make acquisitions on economically acceptable terms or efficiently and effectively integrate the acquired midstream assets with our existing asset base, our future growth will be limited.

Our ability to grow depends, in part, on our ability to make midstream acquisitions that result in an increase in cash generated from operations. If we are unable to make accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or at all or (3) outbid by competitors, then our future growth will be limited.

From time to time, we may evaluate and seek to acquire midstream assets or businesses that we believe complement our existing business and related assets. We may acquire midstream assets or businesses that we plan to use in a manner materially different from its prior owner’s use. Any acquisition involves potential risks, including:

• the inability to integrate the operations of recently acquired businesses or assets, especially if the assets acquired are in a new business segment or geographic area;

• the diversion of management’s attention from other business concerns;

• the failure to realize expected volumes, revenue, profitability or growth;

• the failure to realize any expected synergies and cost savings;

• the coordination of geographically disparate organizations, systems and facilities;

• the assumption of unknown liabilities;

• the loss of customers or key employees from the acquired businesses; and

• potential environmental or regulatory liabilities and title problems.

The assessment by our management of these risks is inexact and may not reveal or resolve all existing or potential problems associated with an acquisition. Realization of any of these risks could adversely affect our financial condition, results of operations and cash flows. If we consummate any future acquisition, our capitalization and results of operations may change significantly.

We may not be able to retain existing Midstream customers or acquire new customers, which would reduce our revenue and limit our future profitability.

The renewal or replacement of our existing contracts with our Midstream customers at rates sufficient to maintain or increase current revenue and cash flows depends on a number of factors beyond our control, including competition from other midstream service providers and the price of, and demand for, crude oil, gas and NGLs in the markets we serve. The inability of

Table of Contents

Index to Financial Statements

our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.

If our Midstream assets become subject to FERC regulation or federal, state or local regulations or policies change, our financial condition, results of operations and cash flows could be materially and adversely affected.

We believe that our gathering and transportation operations are exempt from regulation by FERC under the NGA. Section 1(b) of the NGA exempts gas gathering facilities from regulation by FERC under the NGA. Although FERC has not made any formal determinations with respect to any of our facilities, we believe that the gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts, or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by us are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGPA and the rules and regulations promulgated under those statutes. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows.

Unlike gas gathering under the NGA, there is no exemption for the gathering of crude oil or NGLs under the ICA. Whether a crude oil or NGL shipment is in interstate commerce under the ICA depends on the fixed and persistent intent of the shipper as to the crude oil’s or NGLs’ final destination, absent a break in the interstate movement. We believe that the crude oil and NGL pipelines in our gathering system meet the traditional tests FERC has used to determine that a pipeline is not providing transportation service in interstate commerce subject to FERC ICA jurisdiction. However, the determination of the interstate or intrastate character of shipments on our crude oil and NGL pipelines depends on the shipper’s intentions and the transportation of the crude oil or NGLs outside of our system, and may change over time. If FERC were to consider the status of an individual facility and the character of a crude oil or NGL shipment, and determine that the shipment is in interstate commerce, the rates for, and terms and conditions of, transportation services provided by such facility would be subject to regulation by FERC under the ICA. Such FERC regulation could change our current revenue stream, increase operating costs, and, depending on the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the ICA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by FERC.

Other state and local regulations also affect our business. We are subject to some ratable take and common purchaser statutes in Oklahoma. Ratable take statutes generally require gatherers to take, without undue discrimination, gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport gas. Federal law leaves any economic regulation of gas gathering to the states, and Oklahoma has adopted complaint-based or other limited economic regulation of gas gathering activities.

Our operations are regulated, and we may incur significant costs and liabilities resulting from compliance with these regulations.

The pipelines we own and operate are subject to stringent and complex regulation related to pipeline safety and integrity management. The federal authority for pipeline safety is the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation and is responsible for regulating the safety of design, construction, testing, operation, maintenance, and emergency response of U.S. oil and gas pipeline facilities. Compliance with PHMSA standards and regulations requires us to incur significant costs. In addition, violations of pipeline safety regulations can result in the imposition of significant penalties.

Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the OCC could result in substantial expenditures for testing, repairs and replacement. If our pipelines fail to meet the safety standards mandated by the OCC or the PHMSA regulations, then we may be required to repair or replace sections of such pipelines or operate the pipelines at a reduced maximum allowable operating pressure, the cost of which cannot be estimated at this time.

Table of Contents

Index to Financial Statements

Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial position. Because certain of our operations are located around areas that may become more populated areas, such as the STACK play, we may incur expenses to mitigate noise, odor and light that may be emitted in our operations and expenses related to the appearance of our facilities. Municipal and other local or state regulations are imposing various obligations including, among other things, regulating the location of our facilities, imposing limitations on the noise levels of our facilities and requiring certain other improvements that increase the cost of our facilities. We are also subject to claims by neighboring landowners for nuisance related to the construction and operation of our facilities, which could subject us to damages for declines in neighboring property values due to our construction and operation of facilities.

In addition, the types and volumes of certain chemicals handled by our processing plants pose process safety management risks, including hazards related to the storage, handling and transportation of raw materials, products and wastes. These potential risks include pipeline and storage tank leaks and ruptures, explosions and fires, mechanical failure and chemical spills and other discharges or releases of toxic or hazardous substances or gases at our sites or during transportation. Managing these process hazards is heavily regulated under the Occupational Safety and Health Administration’s Process Safety Management standard, and compliance with this standard can require significant expenditures. Moreover, violations of this standard can result in the imposition of significant penalties and the partial or total cessation of operations.

The potential adoption of federal, state and local legislative and regulatory initiatives intended to address potential induced seismic activity in the areas in which we operate could result in increased compliance costs and operating restrictions.

Our produced water disposal business is subject to existing laws and regulations with legal requirements that are subject to change which could affect our ability to operate the disposal wells. In response to recent seismic events near produced water disposal wells, federal and some state agencies are investigating whether such wells have contributed to increased seismic activity, and some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has taken numerous regulatory actions in response to concerns related to the operation of produced water disposal wells and induced seismicity, and has issued guidelines to operators in certain areas of the State curtailing injection of produced water due to seismic concerns. Some states have also restricted, suspended or shut down the use of certain disposal wells. Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of produced water into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where produced water injection activities occur or are proposed to be performed. Court decisions or the adoption of any new laws, regulations or directives that restrict our ability to operate our disposal wells could have a material adverse effect on our financial condition and results of operations and cash flows.

In addition to the foregoing risks affecting our Midstream business, many of the risks that apply to our Upstream business also apply to our Midstream business.

Risks Related to Our Securities and Capital Structure

Our only significant asset is the ownership of the general partner interest and an approximate 47% limited partner interest in SRII Opco, and such ownership may not be sufficient to enable us to satisfy our financial obligations, including under the Tax Receivable Agreement.

We have no direct operations and no significant assets other than the ownership of the general partner interest and an approximate 47% limited partner interest in SRII Opco. We will depend on SRII Opco and its subsidiaries, including Alta Mesa and KFM, for distributions, loans and other payments to generate the funds necessary to meet our financial obligations. Subject to certain restrictions, SRII Opco generally is required to (i) make pro rata distributions to its partners, including us, in an amount at least sufficient to allow us to pay our taxes and (ii) reimburse us for certain corporate and other overhead expenses. However, legal and contractual restrictions in agreements governing future indebtedness of SRII Opco and its subsidiaries, including Alta Mesa and KFM, as well as the financial condition and operating requirements of Alta Mesa and KFM may limit our ability to obtain cash from SRII Opco. The earnings from or other available assets of SRII Opco and its subsidiaries, including Alta Mesa and KFM, may not be sufficient to enable us to satisfy our financial obligations. SRII Opco is treated as a partnership for U.S. federal income tax purposes and, as such, will not be subject to any entity-level U.S. federal income tax. Instead, taxable income will be allocated to holders of its SRII Opco Common Units, including us. As a result, we generally

Table of Contents

Index to Financial Statements

will incur income taxes on our allocable share of any net taxable income of SRII Opco. Under the terms of the agreement of limited partnership of SRII Opco (the “SRII Opco LPA”), SRII Opco is obligated to make tax distributions to holders of its SRII Opco Common Units, including us, except to the extent such distributions would render SRII Opco insolvent or are otherwise prohibited by law or any of our current or future debt agreements. In addition to tax expenses, we also incur expenses related to our operations, our interests in SRII Opco and related party agreements, including payment obligations under the Tax Receivable Agreement, and expenses and costs of being a public company, all of which could be significant. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Tax Receivable Agreement.” To the extent that we need funds and SRII Opco or any of its subsidiaries is restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition, including our ability to pay our income taxes when due.

Our stock price may be volatile.

The market prices of our Class A Common Stock and public warrants originally sold in our initial public offering (“Public Warrants”) have been, and we expect them to continue to be, subject to significant volatility, and they have declined significantly from their prices on the closing date of the Business Combination. As of December 31, 2018, the reported closing price of our Class A Common Stock on NASDAQ was $1.00 per share and our Public Warrants was $0.07 per warrant. Such fluctuations could be in response to, among other things, the factors described in this “Risk Factors” section, or other factors, some of which are beyond our control, such as:

• actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar to us;

• changes in the market’s expectations about our operating results;

• success of our competitors;

• our operating results failing to meet the expectation of securities analysts or investors in a particular period;

• changes in financial estimates and recommendations by securities analysts concerning us or the market in general;

• negative perceptions about us based upon the presence of material weakness in internal control;

• outcome of the SEC investigation;

• operating and stock price performance of other companies that investors deem comparable to us;

• changes in laws and regulations affecting our business;

• commencement of, or involvement in, litigation involving us;

• changes in our capital structure, such as future issuances of securities or the incurrence of additional debt;

• the volume of shares of our Class A Common Stock available for public sale;

• any major change in our Board or management;

• sales of substantial amounts of Class A Common Stock by our directors, executive officers or significant stockholders or the perception that such sales could occur; and

• general economic and political conditions such as recessions, interest rates, fuel prices, international currency fluctuations and acts of war or terrorism.

Broad market and industry factors may materially harm the market price of our securities irrespective of our operating performance. The stock market in general and NASDAQ have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of these stocks, and of our securities, may not be predictable. A loss of investor confidence in the market for retail stocks or the stocks of other companies which investors perceive to be similar to us could depress our stock price regardless of our business, prospects, financial conditions or results of operations. A decline in the market price of our securities also could adversely affect our ability to issue additional securities and our ability to obtain additional financing in the future.

Our securities may be delisted from NASDAQ.

Our Class A Common Stock and Public Warrants are currently listed on NASDAQ. However, we cannot assure you that we will be able to comply with the continued listing standards of NASDAQ.

We received letters on April 2, 2019, April 3, 2019 and May 14, 2019 from NASDAQ notifying us that we were not in compliance with NASDAQ Listing Rule 5250(c)(1) because we did not timely file this Annual Report on Form 10-K for the year ended December 31, 2018, we failed to maintain a minimum bid price of $1 per share and we did not timely file our Quarterly Report on Form 10-Q for the quarter ended March 31, 2019. We submitted a plan to NASDAQ on May 29, 2019 to

Table of Contents

Index to Financial Statements

regain compliance with NASDAQ Listing Rule 5250(c)(1) to allow for continued listing. Our plan was accepted by NASDAQ and we were granted an extension until September 30, 2019, to regain compliance with NASDAQ’s filing requirements.

If we fail to comply with the continued listing standards of NASDAQ, our securities may become subject to delisting. If NASDAQ delists our Class A Common Stock or Public Warrants from trading on its exchange for failure to meet the continued listing standards, we and our security holders could face significant material adverse consequences including:

• a limited availability of market quotations for our securities;

• a limited amount of analyst coverage; and

• a decreased ability for us to issue additional securities or obtain additional financing in the future.

If securities or industry analysts do not publish or cease publishing research or reports about us, our business, or our market, or if they change their recommendations regarding our securities adversely, the price and trading volume of our securities could decline.

The trading market for our securities may be influenced by the research and reports that industry or securities analysts may publish about us, our business, our market, or our competitors. We have seen the number of analysts covering our stock reduce to just one. This could limit the interest in our securities and negatively affect their price. We do not have any control over the research and reports published or if they will be published at all. If any analysts who may cover us today or in the future make negative recommendation regarding our securities adversely, or provide more favorable relative recommendations about our competitors, the price of our securities could decline. The loss of the remaining analyst could cause our stock price or trading volume to decline.

There is no guarantee that our Public Warrants will be in the money at a time when they are exercisable, and they may expire worthless; the terms of our Public Warrants may be amended without the consent of all holders.

The exercise price for our Public Warrants is $11.50 per share and our common stock closed at $0.146 per share on June 28, 2019. Accordingly, the Public Warrants are significantly underwater and may not be in the money at a time when they are exercisable, and as such, the Public Warrants may expire worthless.

In addition, the warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and us provides that the terms of the Public Warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision, but requires the approval by the holders of at least 50% of the then outstanding Public Warrants to make any change that adversely affects the interests of the registered holders. Accordingly, we may amend the terms of the Public Warrants in a manner adverse to a holder if holders of at least 50% of the then outstanding Public Warrants approve of such amendment. Although our ability to amend the terms of the Public Warrants with the consent of at least 50% of the then outstanding Public Warrants is unlimited, examples of such amendments could be amendments to, among other things, increase the exercise price of the Public Warrants, shorten the exercise period or decrease the number of shares of our Class A Common Stock purchasable upon exercise of a Public Warrant.

We may redeem the Public Warrants prior to their exercise at a time that is disadvantageous to holders, thereby making their Public Warrants worthless.

We have the ability to redeem the outstanding Public Warrants at any time after they become exercisable and prior to their expiration at a price of $0.01 per warrant, provided that (i) the last reported sale price of our Class A Common Stock equals or exceeds $18.00 per share for any 20 trading days within the 30 trading-day period ending on the third business day before we send the notice of such redemption and (ii) on the date we give notice of redemption and during the entire period thereafter until the time the Public Warrants are redeemed, there is an effective registration statement under the Securities Act covering the shares of our Class A Common Stock issuable upon exercise of the Public Warrants and a current prospectus relating to them is available or we have elected to require the exercise of the Public Warrants on a cashless basis. Redemption of the outstanding Public Warrants could force holders of Public Warrants:

• to exercise their Public Warrants and pay the exercise price therefor at a time when it may be disadvantageous for them to do so;

• to sell their Public Warrants at the then-current market price when they might otherwise wish to hold their Public Warrants; or

• to accept the nominal redemption price which, at the time the outstanding Public Warrants are called for redemption, is likely to be substantially less than the market value of their Public Warrants.

Table of Contents

Index to Financial Statements

Anti-takeover provisions contained in our Charter and bylaws, as well as provisions of Delaware law, could impair a takeover attempt.

Our Charter and bylaws contain provisions that could have the effect of delaying or preventing changes in control or changes in our management without the consent of our Board. These provisions include:

• up to two of our nine directors may be appointed by the holders of the Series A Preferred Stock and up to three of our directors may be appointed by holders of the Series B Preferred Stock without any vote of the holders of Class A Common Stock;

• a board that is classified into three classes of directors with staggered three-year terms;

• no cumulative voting in the election of directors, which limits the ability of minority stockholders to elect director candidates;

• the exclusive right of our Board to elect a director to fill a vacancy created by an increase in the number of directors to serve on our Board or the resignation, death, or removal of a director, which prevents stockholders from being able to fill vacancies on our Board;

• the ability of our Board to determine whether to issue shares of our preferred stock and to determine the price and other terms of those shares, including preferences and voting rights, without stockholder approval, which could be used to significantly dilute the ownership of a hostile acquirer;

• a prohibition on stockholder action by written consent, which forces stockholder action to be taken at an annual or special meeting of our stockholders;

• the requirement that an annual meeting of stockholders may be called only by the chairman of the Board, the chief executive officer, or the Board, which may delay the ability of our stockholders to force consideration of a proposal or to take action, including the removal of directors;

• limiting the liability of, and providing indemnification to, our directors and officers;

• controlling the procedures for the conduct and scheduling of stockholder meetings;

• providing that directors may be removed prior to the expiration of their terms by stockholders only for cause; and

• advance notice procedures that stockholders must comply with in order to nominate candidates to our Board or to propose matters to be acted upon at a stockholders’ meeting, which may discourage or deter a potential acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of directors or otherwise attempting to obtain control of us.

These provisions, alone or together, could delay hostile takeovers and changes in control of us or changes in our Board and management.

As a Delaware corporation, we are also subject to provisions of Delaware law, including Section 203 of the Delaware General Corporation Law, which prevents some stockholders holding more than 15% of our outstanding voting common stock from engaging in certain business combinations without approval of the holders of substantially all of our outstanding voting common stock. Any provision of our Charter or bylaws or Delaware law that has the effect of delaying or deterring a change in control could limit the opportunity for our stockholders to receive a premium for their securities and could also affect the price that some investors are willing to pay for our securities.

If a significant portion of our total outstanding shares were sold into the market in the near future, the market price of our Class A Common Stock could drop significantly.

Sales of a substantial number of shares of Class A Common Stock in the public market could occur at any time. The holders of our founder shares, which include Silver Run Sponsor II, LLC (our “Sponsor”) and independent directors, and Fund VI Holdings own approximately 36% of our Class A Common Stock that is currently outstanding. In addition, the Contributors have a redemption or exchange right with respect to all of their respective SRII Opco Common Units. If the Contributors and their permitted transferees redeem or exchange all of their SRII Opco Common Units for shares of Class A Common Stock, they will collectively own approximately 53% of our Class A Common Stock following such redemption or exchange. The sale by these holders of a large number of shares, or the perception in the market that the holders of a large number of shares intend to sell shares, could reduce the market price of our Class A Common Stock.

A significant percentage of our outstanding voting common stock is held by High Mesa Holdings and our Sponsor.

Table of Contents

Index to Financial Statements

High Mesa Holdings, together with its affiliates, and our Sponsor, together with its affiliates, beneficially own approximately 35% and 22%, respectively, of our voting common stock. As long as these entities own or control a significant percentage of outstanding voting power, they will each have the ability to strongly influence all corporate actions requiring stockholder approval, including the election and removal of directors and the size of our Board, any amendment of Charter or bylaws, or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets.

The interests of High Mesa Holdings and our Sponsor and their respective affiliates may not align with the interests of our other stockholders. Our Sponsor is in the business of making investments in companies and may acquire and hold interests in businesses that compete directly or indirectly with us. Our Sponsor and its affiliates may also pursue acquisition opportunities that may be complementary to our business, and, as a result, those acquisition opportunities may not be available to us. In addition, our Charter provides that we renounce any interest or expectancy in the business opportunities of our officers and directors and their respective affiliates and each such party shall not have any obligation to offer us those opportunities unless presented to one of our directors or officers in his or her capacity as a director or officer.

We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may claim, and the amounts of such payments could be significant.

In connection with the completion of the Business Combination, we entered into the Tax Receivable Agreement with the AM Contributor and the Riverstone Contributor (the “Initial Limited Partners”) and SRII Opco. Pursuant to the Tax Receivable Agreement, we will be required to make cash payments to the Initial Limited Partners and their permitted transferees (together, the “TRA Holders”) equal to 85% of the amount of tax benefits, if any, that we actually realize (or are deemed to realize in certain circumstances) in periods after the Business Combination as a result of (i) certain tax basis increases resulting from the exchange of SRII Opco Common Units for Class A Common Stock (or, under certain circumstances, cash) pursuant to the redemption right or our right to effect a direct exchange of SRII Opco Common Units under the SRII Opco LPA, other than such tax basis increases allocable to assets held by KFM or otherwise used in our Midstream business, and (ii) interest paid or deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. We will retain the benefit of the remaining 15% of these cash savings. The amount of the cash payments that we may be required to make under the Tax Receivable Agreement could be significant and is dependent upon significant future events and assumptions, including the timing of the exchanges of SRII Opco Common Units, the price of our Class A Common Stock at the time of each exchange, the extent to which such exchanges are taxable transactions and the amount of the exchanging TRA Holder’s tax basis in its SRII Opco Common Units at the time of the relevant exchange. The amount of such cash payments is also based on assumptions as to the amount and timing of taxable income we generate in the future, the U.S. federal income tax rate then applicable and the portion of our payments under the Tax Receivable Agreement that constitute interest or give rise to depreciable or amortizable tax basis. Moreover, payments under the Tax Receivable Agreement will be based on the tax reporting positions that we determine, which tax reporting positions are subject to challenge by taxing authorities. We will be dependent on distributions from SRII Opco to make payments under the Tax Receivable Agreement, and we cannot guarantee that such distributions will be made in sufficient amounts or at the times needed to enable us to make our required payments under the Tax Receivable Agreement, or at all. Any payments made by us to the TRA Holders under the Tax Receivable Agreement will generally reduce the amount of overall cash flow that might have otherwise been available to us. To the extent that we are unable to make timely payments under the Tax Receivable Agreement for any reason, the unpaid amounts will be deferred and will accrue interest until paid by us. Nonpayment for a specified period may constitute a breach of a material obligation under the Tax Receivable Agreement, and therefore, may accelerate payments due under the Tax Receivable Agreement. The payments under the Tax Receivable Agreement are also not conditioned upon the TRA Holders maintaining a continued ownership interest in SRII Opco or us. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Tax Receivable Agreement” for a discussion of the Tax Receivable Agreement and the related likely benefits to be realized by us and the TRA Holders.

We will not be reimbursed for any payments made to TRA Holders under the Tax Receivable Agreement in the event that any tax benefits are disallowed.

We will not be reimbursed for any cash payments previously made to the TRA Holders pursuant to the Tax Receivable Agreement if any tax benefits initially claimed by us are subsequently challenged by a taxing authority and are ultimately disallowed. Instead, any excess cash payments made by us to a TRA Holder will be netted against any future cash payments that we might otherwise be required to make under the terms of the Tax Receivable Agreement. However, a challenge to any tax benefits initially claimed by us may not arise for a number of years following the initial time of such payment or, even if challenged early, such excess cash payment may be greater than the amount of future cash payments that we might otherwise be required to make under the terms of the Tax Receivable Agreement and, as a result, there might not be future cash payments

Table of Contents

Index to Financial Statements

from which to net against. The applicable U.S. federal income tax rules are complex and factual in nature, and there can be no assurance that the Internal Revenue Service or a court will not disagree with our tax reporting positions. As a result, it is possible that we could make cash payments under the Tax Receivable Agreement that are substantially greater than our actual cash tax savings. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Tax Receivable Agreement” for a discussion of the Tax Receivable Agreement and the related likely benefits to be realized by us and the TRA Holders.

Certain of the TRA Holders have substantial control over us, and their interests, along with the interests of other TRA Holders, in our business may conflict with the holders of our Class A Common Stock.

The TRA Holders may receive payments from us under the Tax Receivable Agreement upon any redemption or exchange of their SRII Opco Common Units, including the issuance of shares of our Class A Common Stock upon any such redemption or exchange. As a result, the interests of the TRA Holders may conflict with the interests of holders of our Class A Common Stock. For example, the TRA Holders may have different tax positions from us which could influence their decisions regarding whether and when to dispose of assets, whether and when to incur new or refinance existing indebtedness, especially in light of the existence of the Tax Receivable Agreement, and whether and when we should terminate the Tax Receivable Agreement and accelerate our obligations thereunder. In addition, the structuring of future transactions may take into consideration tax or other considerations of TRA Holders even in situations where no similar considerations are relevant to us. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Tax Receivable Agreement” for a discussion of the Tax Receivable Agreement and the related likely benefits to be realized by us and the TRA Holders.

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

The Tax Receivable Agreement provides that if we breach any of our material obligations under the Tax Receivable Agreement or if, at any time, we elect an early termination of the Tax Receivable Agreement, then the Tax Receivable Agreement will terminate and our obligations, or our successor’s obligations, to make payments under the Tax Receivable Agreement would accelerate and become immediately due and payable. The amount due and payable in those circumstances is determined based on certain assumptions, including an assumption that we would have sufficient taxable income to fully utilize all potential future tax benefits that are subject to the Tax Receivable Agreement. We may need to incur debt to finance payments under the Tax Receivable Agreement to the extent our cash resources are insufficient to meet our obligations under the Tax Receivable Agreement as a result of timing discrepancies or otherwise.

As a result of the foregoing, (i) we could be required to make cash payments to the TRA Holders that are greater than the specified percentage of the actual benefits we ultimately realize in respect of the tax benefits that are subject to the Tax Receivable Agreement, and (ii) we would be required to make a cash payment equal to the present value of the anticipated future tax benefits that are the subject of the Tax Receivable Agreement, which payment may be made significantly in advance of the actual realization, if any, of such future tax benefits. In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combination, or other changes of control due to the additional transaction costs a potential acquirer may attribute to satisfying such obligations. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

Non-U.S. holders may be subject to U.S. income tax with respect to gain on disposition of their Class A Common Stock and Public Warrants.

We believe that we are a United States real property holding corporation (a “USRPHC”). As a result, non-U.S. holders that own (or are treated as owning under constructive ownership rules) more than a specified amount of our Class A Common Stock or Public Warrants during a specified time period may be subject to U.S. federal income tax on a sale, exchange, or other disposition of such Class A Common Stock or Public Warrants and may be required to file a U.S. federal income tax return. If you are a Non-U.S. holder, we urge you to consult your tax advisors regarding the tax consequences of such treatment.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties

Upstream Segment

Overview

As of December 31, ~~2018~~2019, we ~~have~~held a highly contiguous position of ~~140~~approximately 127,~~400~~100 net acres in the up-dip, naturally-fractured oil portion of the STACK, primarily in eastern Kingfisher and south-eastern Major Counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. This position is characterized by multiple productive zones located at total vertical depths between 4,000 feet and 8,000 feet.

At December 31, ~~2018~~2019, we had aan average 66% ~~average~~net working interest in ~~786~~814 gross producing wells. At December 31, 2018, we had six horizontal drilling rigs operating in the STACK, but by late February 2019, we had no rigs operating. We restarted our development program in March 2019 and expected to use 2 rigs for the remainder of 2019 as we focused on the optimal completion design, well pattern and lowering well costs. Following the August 2019 borrowing base redetermination, we have decided to operate 1 rig starting in September. We will continue to evaluate how much, if any, upstream development will take place going forward.

~~Bayou City Joint Development Agreement~~10

In January 2016, we entered into a joint development agreement (as subsequently amended, the “JDA”) with BCE-STACK Development LLC (“BCE”), a fund advised by Bayou City Management, LLC, to fund a portion of our drilling operations with the intent to accelerate our development. The JDA establishes a development plan of 60 wells in three tranches, and provides

Table of Contents

Index to Financial Statements

~~opportunities~~After ~~for~~the Business Combination, we conducted development activities using a spacing array of 6 to 10 wells per section and running up to 9 rigs at the ~~parties~~peak activity level. In late 2018, our production across the acreage evidenced that the well spacing was not delivering the expected well level production. During January 2019, we suspended our development program to ~~potentially~~allow ~~agree~~our new management team to anconduct ~~additional~~a 20full ~~wells~~operational and economic review. AsWe restarted our development program in March 2019 with a less dense spacing pattern of ~~December 31,~~up ~~2018~~to five wells per section and began operating 2 rigs, 61however ~~joint~~following ~~wells~~our ~~had~~filing ~~been~~for ~~drilled~~bankruptcy orprotection ~~spudded~~in September 2019, we discontinued further development activities.

~~Under~~Bayou ~~the~~City ~~JDA,~~Joint upDevelopment to 100% of our well costs could be funded up to a specified total well cost. We are responsible for any drilling and completion costs exceeding approved amounts. In exchange for BCE carrying the drilling and completion costs, they receive 80% of our working interest in each funded well until attaining a 15% internal rate of return for the entire tranche, at which time their interest reduces to 20%. If a tranche attains a 25% internal rate of return, their interest reduces to 12.5%.Agreement

~~During~~In ~~the~~January ~~Successor Period~~2016, we ~~brought~~entered 25into ~~horizontal~~a ~~wells~~joint ondevelopment ~~production~~agreement ~~that~~(as ~~were~~subsequently ~~funded~~amended, ~~through~~ the “JDA.”) Atwith ~~December 31,~~BCE-STACK ~~2018~~Development LLC (“BCE”), ~~there~~a ~~were~~fund noadvised ~~funded~~by ~~horizontal~~Bayou ~~wells~~City inManagement, ~~progress~~LLC, ~~and~~to wefund doa ~~not~~portion ~~expect~~of ~~any~~our ~~wells~~drilling tooperations bewith ~~developed~~the inintent ~~2019 pursuant~~ to ~~the~~accelerate ~~JDA~~our development. OnThe ~~June~~JDA ~~11,~~established ~~2019,~~a wedevelopment ~~received~~plan aof ~~letter~~60 ~~from~~wells ~~BCE~~in ~~noticing~~three ustranches, ofand ~~alleged~~provided ~~defaults~~opportunities ~~under~~for the ~~JDA~~parties to potentially agree to an additional 20 wells. WeAs ~~dispute~~of ~~these~~December 31, ~~allegations~~2019, ~~and~~61 ~~intend~~joint towells ~~vigorously~~had ~~defend~~been ~~ourselves.~~drilled or spudded.

Under the JDA, up to 100% of our well costs could be funded up to a specified total well cost. In exchange for BCE carrying the drilling and completion costs, they received 80% of our working interest in each funded well until attaining a 15% internal rate of return for the entire tranche, at which time their interest reduces to 20%. If a tranche attains a 25% internal rate of return, their interest reduces to 12.5%.

During the 2018 Successor Period, we brought 25 horizontal wells on production that were funded through the JDA. At December 31, 2019, there were no JDA wells in progress, and none have been developed in 2020. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and intend to vigorously defend ourselves. The JDA expired in January 2020 pursuant to its terms.

Our Oil and Gas Reserves

Our proved reserves and production profile as of December 31, ~~2018~~2019 was as follows:

Total Estimated Proved Reserves (MMBoe)	Percent Proved Developed ~~(1)~~	~~Liquids~~PV-10($ asin ~~a Percentage of Total Proved Reserves~~ millions)(1)	~~PV-10~~Standardized Measure ($ in millions) (21)	~~Standardized~~Net ~~Measure~~Producing Wells(~~$ in millions) (~~2)	Average 2019 Daily Net ~~Acreage~~Production (3MBoe/d)	~~Net Producing Wells (4)~~	~~Average 2018 Daily Net Production (MBoe/d) (5)~~
69.1	100%	65%	$812.9	$714.3	140,400	517.9	31.1
46.5	100%	$346.3	$326.9	535	35.0

_________________

(1) ~~Computed~~PV-10 asis a ~~percentage~~non-GAAP measure of ~~total~~the estimated future net cash flows from proved reserves before giving effect to income taxes, discounted at an annual rate of 10 percent. ~~Based~~The oncalculation of PV-10 also does not give effect to potential derivatives or hedging transactions. Standardized measure is the after-tax estimated future net cash flows from proved reserves discounted at an annual rate of 10 percent and may (depending upon a registrant’s derivative and hedging policy) include the effects of hedges, all determined in accordance with GAAP. We believe PV-10 is a useful measure of the value of our ~~April~~proved ~~2019~~reserves ~~assessment~~because it allows users of our ~~ability~~financial statements to ~~continue~~compare asrelative avalues ~~going~~and ~~concern~~sizes of proved reserves among exploration and ~~our~~production ~~expected~~companies ~~inability~~without regard to ~~fund~~their ~~development~~corporate ~~costs,~~structure weand ~~removed~~the aresulting ~~total~~income tax burden. The difference between PV-10 and standardized measure is the discounted effect of 89income taxes,~~073~~ ~~MBoe~~totaling of$19.4 ~~PUDs~~million, ason our share of ~~December~~expected 31future net cash flows, ~~2018~~without taking into consideration the utilization of net operating loss carryforwards.

(2) ~~PV-10~~Calculated isas agross ~~non-GAAP~~wells ~~measure~~multiplied ofby the estimated future net cash flows from proved reserves before giving effect to income taxes, discounted at an annual rate of 10 percent. The calculation of PV-10 also does not give effect to derivatives or hedging transactions. Standardized measure is the after-tax estimated future net cash flows from proved reserves discounted at an annual rate of 10 percent and may (depending upon a registrant’s derivative and hedging policy) include the effects of hedges, all determined in accordance with GAAP. We believe PV-10 is a useful measure of the value of our ~~proved~~working ~~reserves~~interest ~~because~~percentage itfor ~~allows~~each users of our financial statements to compare relative values and sizes of proved reserves among exploration and production companies without regard to their corporate structure and the resulting income tax burdenwell. The difference between PV-10 and standardized measure is the discounted effect of income taxes, totaling $98.6 million, on our share of expected future net cash flows, without taking into consideration the utilization of net operating loss carryforwards or other tax credits.

~~(3) Includes developed and undeveloped acreage.~~11

(4) Calculated as gross wells multiplied by our working interest percentage for each well.

(5) Average daily net production for the Successor Period.

Table of Contents

Index to Financial Statements

Key information and assumptions used in determining our estimated net proved reserves at the end of each period is set forth in Item 8. All of our reserves are located in the United States. ~~The~~ ~~information presented during the Predecessor Periods includes amounts related to discontinued operations.~~

Oil and NGLS (Mbbls)

Successor

~~Predecessor~~

Predecessor

December 31, 2018

February 8, 2018

December 31, 2017

December 31, 2016

December 31, 2019

December 31, 2018

February 8, 2018

Proved Reserves (1)

Developed

4527,~~064~~431

45,064

~~30,693~~

3230,~~527~~693

~~24,809~~

Undeveloped

—

~~77,256~~

77,~~878~~256

~~61,280~~

Total

4527,~~064~~431

45,064

~~107,949~~

~~110~~107,~~405~~949

~~86,089~~

Average market prices (per bbl) - oil(2)

6555.5669

$65.56

~~52.89~~

5152.3489

~~42.75~~

Average realized prices (per bbl) - NGLs(2)

2214.4460

$22.44

~~27.48~~

2627.0648

~~15.18~~

Natural Gas (MMcf)

Successor

~~Predecessor~~

Predecessor

December 31, 2018

February 8, 2018

December 31, 2017

December 31, 2016

December 31, 2019

December 31, 2018

February 8, 2018

Proved Reserves (1)

Developed

~~144~~114,~~148~~443

144,148

~~126,231~~

~~150~~126,~~183~~231

~~93,361~~

Undeveloped

—

~~284,571~~

~~283~~284,~~336~~571

~~222,644~~

Total

~~144~~114,~~148~~443

144,148

~~410,802~~

~~433~~410,~~519~~802

~~316,005~~

Average market prices (per MMBtu) - natural gas(2)

32.1058

$3.10

~~2.99~~

2.9899

~~2.49~~

Total (MBoe)

Successor

~~Predecessor~~

Predecessor

December 31, 2018

February 8, 2018

December 31, 2017

December 31, 2016

December 31, 2019

December 31, 2018

February 8, 2018

Proved Reserves (1)

Developed

6946,~~089~~505

69,089

~~51,731~~

5751,~~557~~731

~~40,371~~

Undeveloped

—

~~124,685~~

~~125~~124,~~101~~685

~~98,386~~

Total

6946,~~089~~505

69,089

~~176,416~~

~~182~~176,~~658~~416

~~138,757~~

_________________

(1) Proved reserves were calculated using oil and gas parameters established by current SEC guidelines and accounting rules. Reserve estimates are based on various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Actual future production, oil and gas prices, revenue, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary from these estimates. In addition, we may adjust our estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. ~~Sustained lower prices may result in the estimated quantities and present values of our reserves being reduced and may necessitate future impairments of our capitalized costs.~~


(2)	Average market prices represent an unweighted arithmetic average of the market price on the first day of each month during the last 12 months.

4712

Table of Contents

Index to Financial Statements

Proved Undeveloped Reserves

Based on Alta Mesa’s bankruptcy filing and/or our inability to fund development costs, we did not recognize any PUDs as of December 31, 2019 and 2018. The information presented during the 2018 Predecessor ~~Periods~~Period includes amounts related to discontinued operations. Changes in our proved undeveloped reserves during the 2018 Successor Period and the 2018 Predecessor Period were (in MBoe):

	Successor			~~Predecessor~~		Predecessor
	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
	Year Ended December 31, 2019		February 9, 2018ThroughDecember 31, 2018			January 1, 2018ThroughFebruary 8, 2018
Beginning of period	~~124,685~~—		124,685	~~125,101~~		98125,~~386~~101		~~44,624~~
Converted into proved developed reserves	~~(18,999~~—	)	(18,999	—)		~~(4,083~~—	)	~~(1,509~~	)
Extensions and discoveries	~~43,354~~—		43,354	—		~~32,972~~—		~~51,306~~
Reserves acquired	~~3,738~~—		3,738	—		~~1,846~~—		—
Reserves sold/distributed(1)	—		—	~~(1,129~~	)	(~~746~~1,129	)	—
Revisions(2)	~~(152,778~~—	)	(152,778	~~713~~)		~~(3,274~~713	)	~~3,965~~
End of period	—		—	~~124,685~~		~~125~~124,~~101~~685		~~98,386~~
Percentage of total proved reserves	—	%	—	71%	%	6871	%	71	%

_________________

(1) Reserves sold/distributed during the period January 1, 2018 to February 8, 2018, represent amounts related to our non-STACK properties that are classified as discontinued operations in our ~~consolidated~~ financial statements.

(2) Effective as of December 31, 2018, due to uncertainty regarding our ability to continue as a going concern and the availability of capital that would be required to develop the proved undeveloped reserves, we ~~have~~ removed all of our PUDs from our total estimated proved reserves.

During ~~the~~2019, ~~Successor~~we ~~Period~~did not incur any expenses to develop PUD reserves, wecompared ~~incurred~~to approximately $160.6 million inincurred ~~expenditures~~during tothe ~~develop~~2018 ~~PUD~~Successor ~~reserves~~Period. PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of the original date of their recognition. As ~~The~~a ~~identification~~result ~~and development~~ of ~~PUDs~~Alta inMesa’s ~~the~~bankruptcy ~~future~~filing ~~is dependent on future commodity prices, costs, capital availability~~ and ~~other economic assumptions. During January 2019, we finalized our development plan for~~ the ~~next~~expected ~~five~~Sale ~~years and received an audit report from our outside engineers that agreed with our recognition of PUDs for the majority of that future development. During April 2019~~Transactions, ~~in finalizing our financial reporting for 2018,~~ we ~~determined~~do ~~that~~not weexpect ~~may fail~~ to ~~satisfy~~incur ~~the~~any ~~leverage~~further ~~covenant~~development ~~under the Alta Mesa RBL during 2019. Accordingly, we were unable to conclude that we would have a high likelihood~~ of ~~continued~~our ~~access to that capital source~~properties. Thus, we have concluded that we ~~did~~do not satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our ~~future~~available drilling locations ~~and did not recognize any proved undeveloped locations in our final December 31, 2018 reserve report received in April 2019~~. ~~Should our ability to fund the required development costs improve in the future, we expect to recognize all or a portion of those resources as proved.~~

Internal Controls Over Reserve Estimates and Qualifications of Technical Persons

Our policies and practices regarding internal controls over reserve recognition are structured to objectively and accurately estimate our oil and gas reserves quantities and their present value in compliance with SEC standards. The reserve estimation process begins with our Corporate Reserves department, which gathers and analyzes much of the data used as inputs to estimating reserves. Working and net revenue interests are sourced from our division order system in our land department. Lease operating expenses are provided by our accounting department and our operations team provides capital expenses. Our Vice President of Planning and Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. His qualifications include the following:


•	Over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves; and


•	Bachelor of Science Degree in Petroleum Engineering from the University of Texas in 1980, Master of Business Administration from Oklahoma City University in 1988.

Our methodologies include reviews of production trends, material balance calculations, analogy to comparable properties, and volumetric analysis, with performance methods preferred. Reserve estimates for developed non-producing properties and for undeveloped properties are based primarily on analogy to offset production in the same area.

We maintain internal controls that we believe result in the proper amount and value of our reported reserves. These controls, which we determined to be effective for all periods presented, include:

Table of Contents

Index to Financial Statements


•	we follow comprehensive SEC-compliant internal policies to determine and report proved reserves;


•	reserve estimates are made by experienced reservoir engineers or under their direct supervision; and

• annually, our Chief Operating Officer and Chief Executive Officer review all significant reserves changes and ~~all~~ new proved undeveloped reserves additions.

Ryder Scott Company, LP (“Ryder Scott”), a third-party petroleum engineering consulting firm, audited approximately 96% of our 2018 proved reserves on a 6:1 Mcf per Bbl conversion basis. Their report is filed with this Annual Report as Exhibit 99.1. The reserve audit by Ryder Scott conformed to the meaning of “reserves audit” as presented in the SEC’s Regulation S-K, Item 1202. The qualifications of the technical person at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.13

~~Miles~~Table ~~R. Palke earned a B.S. in Petroleum Engineering from Texas A&M University in College Station, Texas and a Master~~ of Science in Petroleum Engineering from Stanford University in Palo Alto California. Mr. Palke graduated Magna Cum Laude and with University Honors from Texas A&M University and is a registered Professional Engineer in the State of Texas. Based on his educational background, professional training and more than 22 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Palke has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. Contents

Index to Financial Statements

Ryder Scott Company, LP (“Ryder Scott”), a third-party petroleum engineering consulting firm, audited approximately 97% of our 2019 proved reserves on a 6:1 Mcf per Bbl conversion basis. Their report is filed with this Annual Report as Exhibit 99.1. The reserve audit by Ryder Scott conformed to the meaning of “reserves audit” as presented in the SEC’s Regulation S-K, Item 1202. The qualifications of the technical person at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.

Miles R. Palke with Ryder Scott earned a B.S. in Petroleum Engineering from Texas A&M University in College Station, Texas and a Master of Science in Petroleum Engineering from Stanford University in Palo Alto California. Mr. Palke graduated Magna Cum Laude and with University Honors from Texas A&M University and is a registered Professional Engineer in the State of Texas. Based on his educational background, professional training and more than 23 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Palke has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers.

A reserves audit and a financial audit are separate activities with unique and different processes and results. A reserves audit under SEC standards is the process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities.

Oil and Gas Production, Production Prices and Production Costs

Information relating to our oil and gas production, sales prices for our products produced and production costs is included in Item 17.

Drilling and Other Exploratory and Development Activities

Successor

~~Predecessor~~

Predecessor

February 9, 2018 Through December 31, 2018

January 1, 2018 ThroughFebruary 8, 2018

Year EndedDecember 31, 2017

Year EndedDecember 31, 2016

Year Ended December 31, 2019

February 9, 2018ThroughDecember 31, 2018

January 1, 2018ThroughFebruary 8, 2018

Development wells (net):

Development wells drilled (net):

Productive

~~123~~48.8

123.8

~~7.0~~

597.0

~~29.9~~

Dry

—

Total development wells

~~123~~48.8

123.8

~~7.0~~

597.0

~~29.9~~

Exploratory wells (net):

Exploratory wells drilled (net):

Productive

—

~~0.1~~—

~~3.0~~

Dry

~~1.0~~—

1.0

—

Total exploratory wells

~~1.0~~—

1.0

—

~~0.1~~—

~~3.0~~

Activities at Year End

At December 31, ~~2018~~2019, we had 32no ~~gross (26 net)~~ wells that were in progress for drilling or completion operations.

Delivery Commitments

Information about our firm transportation commitments is included in Part II, Item 78.

Productive Wells, Developed and Undeveloped Acreage

49The following sets forth information with respect to our wells and acreage under lease as of December 31, 2019, all of which is located in the United States:

Table of Contents

Index to Financial Statements

The following sets forth information with respect to our wells and acreage under lease as of December 31, 2018, all of which is located in the United States:



	December 31, 2019
	Gross	Net
Number of producing wells principally targeting ⁽¹⁾:
Oil	792	521.8
Gas	22	13.2
Total wells	814	535

Properties:
Developed acres	176,455	110,412
Undeveloped acres	39,085	16,647
Total acres	215,540	127,059

Undeveloped acreage expirations ⁽²⁾:
Year ending December 31, 2020	11,301	4,504
Year ending December 31, 2021	17,428	5,969
Total	28,729	10,473

	December 31, 2018
	Gross	Net
Number of productive wells principally targeting (1):
Oil	760	502.6
Gas	26	15.3
Total wells	786	517.9
Properties:
Developed acres	166,955	112,088
Undeveloped acres	53,741	28,314
Total acres	220,696	140,402
Undeveloped acreage expirations (2):
Year ending December 31, 2019	13,942	7,213
Year ending December 31, 2020	14,183	5,636
Year ending December 31, 2021	12,778	6,493
Total	40,903	19,342

_________________

(1) ~~Productive wells are producing wells and those wells we deem capable of production.~~ A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractional working interests we own in gross wells, including joint development wells.

(2) Our lease acreage is typically subject to expirations if a well is not drilled and producing before the end of the primary term. The primary term of our leasehold ranges from 3 to 5 years. As is customary in our industry, our undeveloped leasehold may be maintained through: (i) commencing operations for drilling, completion and production, (ii) pooling, (iii) extensions or renewals and (iv) other operational extensions, including shut-in payments and continuous operations. As of December 31, 2018, the majority of our undeveloped acreage subject to expiry does not have associated proved reserves. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests.

Title to Properties

We typically conduct a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, at the time we acquire properties. We believe that title to our interests is satisfactory and consistent with the standards in our industry. The interests owned by us may be subject to one or more royalty, overriding royalty net profits interests, liens and taxes or other outstanding interests (including disputes related to such interests) customary in the industry.

Midstream Segment

Our KFM assets include a gas and oil gathering network, a cryogenic gas processing plant with off-take capacity, field compression facilities and a produced water disposal system. These assets are located in the Anadarko Basin in Oklahoma.

KFM ~~has also~~ expanded its gas gathering system northward into Major County, Oklahoma, with a high-pressure line to connect the existing system in Kingfisher County, Oklahoma to new low-pressure gathering pipelines in southeastern Major County.

Prior to November 2019, KFM ~~holds~~held a 50% equity interest in a partnership to develop a long-haul crude oil pipeline project, the Cimarron Express Pipeline (“Cimarron”), that was designed to link the existing crude oil storage tank located at the KFM Lincoln Terminal to a crude oil terminal site at Cushing, Oklahoma. Based on lower oil prices, less ~~down spacing of~~ development wells, and lower expected volumes from new wells, we determined in the fourth quarter of 2018 that the project was not likely to be completed and recognized an impairment to reduce our investment to its estimated fair value at December 31, 2018. In November 2019, Cimarron redeemed its 50% membership interest from the third party for one-half of the remaining cash in Cimarron plus an immaterial amount of other equipment. Following this transaction, Cimarron became our wholly owned subsidiary.

In November 2018, Alta Mesa sold substantially all of its produced water assets to a subsidiary of KFM, consisting of over 200 miles of produced pipelines, and related facilities and equipment, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations.

50Item 3. Legal Proceedings

Table of Contents

Index to Financial Statements

~~Item 3~~assessing contingencies is highly subjective and requires judgments about uncertain future events. ~~Legal~~When ~~Proceedings~~evaluating contingencies, we may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The commencement of the Chapter 11 proceedings automatically stayed most of these actions against the Company.

We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business, the outcomes of which cannot be reasonably estimated. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, we may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. Bankruptcy

On September 11, 2019, AMR, Alta Mesa and all of its subsidiaries (the “AMH Debtors” and together with AMR, the “Initial Debtors”) filed voluntary petitions (“Initial Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).

On January 12, 2020, KFM and all of its subsidiaries (collectively, the “KFM Debtors”) filed voluntary petitions (“ KFM Bankruptcy Petitions”) for relief under the Bankruptcy Code. On January 13, 2020, SRII Opco GP, LLC and SRII Opco (collectively, the “SRII Debtors” and, together with the KFM Debtors, the “Additional Debtors”) filed voluntary petitions (“SRII Bankruptcy Petitions and, together with the KFM Bankruptcy Petitions, the “Additional Bankruptcy Petitions”) for relief under the Bankruptcy Code. The Additional Debtors’ Chapter 11 cases are being jointly administered with the Initial Debtors’ Chapter 11 cases.

Adversary Proceeding

On September 12, 2019, an adversary proceeding was commenced by certain of the AMH Debtors against KFM, Oklahoma Produced Water Solutions, LLC, SRII Opco, HMI, Michael E. Ellis, and Harlan H. Chappelle (together, the “Defendants”), alleging, among other things, that (i) the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions and KFM and its subsidiaries could be rejected, (ii) certain amendments to the crude oil and gas gathering agreements were constructive and actual fraudulent transfers, (iii) the Defendants breached their respective fiduciary duties owed to the AMH Debtors by entering related-party crude oil and gas gathering agreements, which as a result are subject to rescission, and (iv) KFM and its subsidiaries materially breached the crude oil gathering agreement and that the agreement is therefore terminated. Pursuant to the adversary proceeding complaint, AMH is seeking declaratory judgements that the gathering agreements cannot continue to burden AMH or its estates and could therefore be rejected or avoided under the Bankruptcy Code. On October 25, 2019, the plaintiff AMH Debtors filed an amended complaint naming only KFM and Oklahoma Produced Water Solutions, LLC as Defendants.

On December 6, 2019, the Bankruptcy Court held that the dedication provisions of the crude oil, gas and water gathering agreements “ran with the land” and therefore could not be rejected under the Bankruptcy Code, granting summary judgment in favor of the defendants on that count of the complaint. All other counts were reserved for trial, which commenced on December 9, 2019, but was subsequently stayed by the Bankruptcy Court at the request of the parties. The litigation remains stayed as of the date hereof.

Litigation

On January 30, 2019, the Company, James T. Hackett, our then interim Chief Executive Officer and Chairman of the Board, certain of our former and current directors, Thomas J. Walker, our former Chief Financial Officer, and Riverstone Investment Group LLC were named as defendants in a putative securities class action filed in the United States District Court for the Southern District of New York (“SDNY Complaint”). The plaintiff, Plumbers and Pipefitters National Pension Fund, alleges that the defendants disseminated a false and misleading proxy statement in connection with the Business Combination and, therefore, violated Section 14(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Rule 14-9 promulgated thereunder. In addition, the plaintiff alleges that Riverstone and the individual defendants violated Section 20(a) of the Exchange Act. The plaintiff is seeking compensatory and/or rescissory damages against the defendants. The District Court transferred this action to the U.S. District Court for the Southern District of Texas.

On March 14 and 19, 2019, two additional putative securities class action complaints were filed in the U.S. District Court for the Southern District of Texas (“SDTX Complaints”) against the same defendants named in the SDNY Complaint, and Harlan H. Chappelle ~~and Michael A. McCabe~~, our former President and Chief Executive Officer, and Michael A. McCabe, our former Chief Financial Officer~~, respectively~~. These complaints include the same claims asserted in the initial complaint, but also add claims under Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder against us and certain of our current and former officers and directors on behalf of all persons or entities who purchased or otherwise acquired Silver Run or AMR securities between March 24, 2017, and February 25, 2019. The new claims are based upon alleged misstatements contained in our proxy statement and made after the Business Combination. The plaintiffs seek compensatory and/or rescissory damages against the defendants.

The outcome of the above securities class action complaints is uncertain, and while we believe that we have valid defenses to the plaintiff’s claims and intend to defend the lawsuits vigorously, no assurance can be given as to the outcome of the lawsuits. 16

OnTable ~~March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court~~ of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including certain of our affiliates and subsidiaries. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to KFM in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants. We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves. Contents

InIndex August 2017, Biloxi Marsh Lands (“Biloxi”) filed suit in the 34th District Court for the Parish of St. Bernard, Louisiana, against Meridian Resource & Exploration LLC (a subsidiary of HMI), Alta Mesa, and other defendants. Biloxi alleges negligent construction, installation, maintenance, use and operation of a pipeline. In lieu of litigating corporate structure allegations and to ~~reduce~~Financial potential litigation expenses, Alta Mesa stipulated with respect to Biloxi that it would be bound by and assume liability and responsibility for any unpaid debts, obligations or final judgments that may be entered against Meridian in favor of Biloxi in this matter. However, these allegations relate to non-STACK oil and gas assets that Alta Mesa distributed to a subsidiary of HMI prior to the Business Combination. In connection with that distribution, certain HMI subsidiaries agreed to indemnify and hold Alta Mesa harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Consequently, we believe that any potential damages incurred by Alta Mesa or Meridian as a result of these allegations are the responsibility of HMI. There is no guarantee that HMI will pay any settlement amounts or judgments rendered against Alta Mesa or Meridian. In addition, Alta Mesa’s ability to collect any amounts due pursuant to these indemnification obligations will depend upon the liquidity and solvency of HMI. Statements

and February 25, 2019. The new claims are based upon alleged misstatements contained in our proxy statement and made after the Business Combination. The plaintiffs seek compensatory and/or rescissory damages against the defendants.

On December 19, 2019, the U.S. District Court for the Southern District of Texas consolidated the three putative securities class action lawsuits into a single action. On January 16, 2020, the Court entered a stipulated order appointing Plumbers and Pipefitters National Pension Fund and the First New York Group (consisting of FNY Partners Fund LP, FNY Managed Accounts LLC, and Paul J. Burbach) as co-lead plaintiffs and appointing Camelot Event Driven Fund as an additional consolidated class representative. The amended Consolidated Putative Securities Class Action complaint is due March 16, 2020. The commencement of the Chapter 11 proceedings automatically stayed these actions against the Company.

The outcome of the above consolidated class actions is uncertain, and while we believe that we have valid defenses to the plaintiff’s claims and intend to defend the lawsuits vigorously, no assurance can be given as to the outcome of the lawsuits.

On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including certain of our affiliates and subsidiaries. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to KFM in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants. We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves. The Mustang litigation was automatically stayed on the commencement of the Chapter 11 proceedings.

Mustang filed an adversary proceeding (Mustang Gas Products LLC v. Oklahoma Energy Acquisitions, LP et al., Adversary Proceeding No. 20-03015 (Bankr. S.D. Tex.)) against Oklahoma Energy Acquisitions, LP (“OEA”) and other defendants on January 20, 2020, alleging that gas dedication covenants running with the land have a value of not less than $37 million, and entitle Mustang to a corresponding portion of the proceeds of the forthcoming sale of all or substantially all of OEA’s assets. OEA denies these allegations and intends to defend the case vigorously. OEA’s time to respond to Mustang’s complaint has been extended until 15 days after the bankruptcy court enters an order on the pending motion to dismiss filed by the Administrative Agent to the Alta Mesa RBL. It is not possible at this stage of the case to estimate the likelihood of an unfavorable outcome or the range of damages that may be awarded.

In August 2017, Biloxi Marsh Lands (“Biloxi”) filed suit in the 34th District Court for the Parish of St. Bernard, Louisiana, against Meridian Resource & Exploration LLC (“Meridian”, a subsidiary of HMI), Alta Mesa, and other defendants. Biloxi alleges negligent construction, installation, maintenance, use and operation of a pipeline. In lieu of litigating corporate structure allegations and to reduce potential litigation expenses, Alta Mesa stipulated with respect to Biloxi that it would be bound by and assume liability and responsibility for any unpaid debts, obligations or final judgments that may be entered against Meridian in favor of Biloxi in this matter. However, these allegations relate to non-STACK oil and gas assets that Alta Mesa distributed to a subsidiary of HMI prior to the Business Combination. In connection with that distribution, certain HMI subsidiaries agreed to indemnify and hold Alta Mesa harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. Consequently, we believe that any potential damages incurred by Alta Mesa or Meridian as a result of these allegations are the responsibility of HMI. There is no guarantee that HMI will pay any settlement amounts or judgments rendered against Alta Mesa or Meridian. In addition, Alta Mesa’s ability to collect any amounts due pursuant to these indemnification obligations will depend upon the liquidity and solvency of HMI, which recently filed for relief under Chapter 7 of the Bankruptcy Code in the Bankruptcy Court. The commencement of the Chapter 11 proceedings automatically stayed these against the Company.

SEC Investigation

51The SEC is conducting a formal investigation into, among other things, the facts involved in the fair value measurements used in accounting for the Business Combination and the impairment charge recognized during 2018. We are cooperating with this investigation. At this point we are unable to predict the timing or outcome of this investigation. If the SEC determines that violations of the federal securities laws have occurred, the agency has a broad range of civil penalties and other remedies available, some of which, if imposed on us, could be material to our business, financial condition or results of operations.

Table of Contents

Index to Financial Statements

The SEC is conducting a formal investigation into, among other things, the facts involved in the material weakness in our internal controls over financial reporting and the impairment charge disclosed elsewhere in our financial statements. We are cooperating with this investigation. At this point we are unable to predict the timing or outcome of this investigation. If the SEC determines that violations of the federal securities laws have occurred, the agency has a broad range of civil penalties and other remedies available, some of which, if imposed on us, could be material to our business, financial condition or results of operations.

Environmental Claims

Various landowners have sued Alta Mesa in lawsuits concerning several fields in which Alta Mesa’s subsidiaries have, or historically had, operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from its oil and gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims inas ~~our~~of ~~consolidated financial statements at~~ December 31, ~~2018~~2019.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

(a) Market Information

Our Class A Common Stock and Public Warrants are currently listed on ~~NASDAQ~~the OTC Pink Marketplace under the symbols “~~AMR~~AMRQQ” and “~~AMRWW~~AMRWQ,” respectively. Over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

Our Class C Common Stock does not trade on any market however, holders of our Class C Common Stock hold an equal number of SRII Opco Common Units that were issued upon the closing of the Business Combination. Holders of Class C Common Stock have the right to cause SRII Opco to redeem all or a portion of their SRII Opco Common Units in exchange for an equal number of shares of our Class A Common Stock or, at SRII Opco’s option, an equivalent amount of cash. Upon such an exchange, a corresponding number of shares of Class C Common Stock would be canceled.

In February 2020, we filed forms with the Securities and Exchange Commission to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act. Further, as part of the AMR Liquidation Plan, we expect all outstanding shares of Class A Common Stock and Class C Common Stock will be cancelled.

(b) Holders

As of ~~June~~January 2831, ~~2019~~2020, there were 1739 holders of record of our Class A Common Stock, 109 holders of record of our Class C Common Stock and 6 holders of record of our Public Warrants. The number of record holders of our Class A Common Stock and Public Warrants does not include DTC participants or beneficial owners holding shares of Public Warrants through nominee names.

We have not paid any cash dividends on our Class A Common Stock to date. The payment of any cash dividends on our Class A Common Stock is within the discretion of our Board of Directors (the “Board”) but, our ability to declare dividends is generally prohibited by our debt agreements and our bankruptcy filing. Holders of our Class C Common Stock are not entitled to dividends at any time.

(d) Securities Authorized for Issuance Under Equity Compensation Plans

~~Information~~Shares ~~required~~of byClass ~~this~~A ~~section~~Common isStock inthat ~~Part~~were ~~III~~issuable under our existing equity compensation plans as of December 31, ~~Item~~2019: ~~12.~~

5218

Table of Contents

Index to Financial Statements



Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders⁽¹⁾				40,016,725
Stock options	3,803,287	$	8.79
PSUs⁽²⁾	2,841,434	N/A
Total	6,644,721			40,016,725

_________________


(1)	There were no equity compensation plans not approved by security holders.


(2)	Assumes maximum achievement of performance targets at 200% for the 2019 and 2020 performance periods. Performance-based restricted stock units have no exercise price. In February 2020, we settled the 2019 tranche of the PSUs with an immaterial cash payment.

On February 11, 2020, we filed a post-effective amendment to our registration statement on Form S-8 (Registration No. 333-224248) to deregister unissued and unsold shares of Class A Common Stock issuable to participants under the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan.

(e) Performance Graph

WeNot do not consider the following information to be “soliciting material” or to be “filed” with the SEC, nor shall the information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except as specified by usrequired.

The following graph compares the total return to stockholders of AMR’s common stock relative to the cumulative total returns of the Russell 2000 index and a selected peer group of twelve companies during the Successor Period. We had no material operations prior to February 9, 2018. Assets prior to February 9, 2018 consisted primarily of proceeds held in a Trust Account from the Company’s initial public offering completed on March 29, 2017, pending use of those funds for completion of a business combination.

An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common stock, in the Russell 2000 index and in each company’s stock in our peer group on February 9, 2018, with the relative weighted average performance of each tracked through December 31, 2018. The returns shown are not intended to suggest future performance. The companies included in the selected peer group are:

EOG Resources, Inc. Range Resources Corporation Marathon Oil Corporation Whiting Petroleum Corporation Pioneer Natural Resources Company Newfield Exploration Company Noble Energy, Inc. Diamondback Energy, Inc. Continental Resources, Inc. Approach Resources, Inc. Concho Resources Inc. Midstates Petroleum Company, Inc.

(f) Recent Sales of Unregistered Securities

None.

(g) Purchases of Equity Securities by the Issuer and Affiliated Purchasers

53In August 2018, our Board authorized the repurchase of up to $50.0 million of the Company’s outstanding Class A Common Stock, exclusive of any fees, commissions or other expenses related to such repurchases. Prior to our bankruptcy filing, repurchases could have been made at the Company’s discretion in accordance with applicable securities laws from time to time in open market or private transactions. All shares repurchased were retired. The authorization has no expiration date.

~~Table~~There ofwere ~~Contents~~no repurchases and retirements during the quarter ended December 31, 2019 and no additional repurchases are anticipated.

Index to Financial Statements

In August 2018, our Board authorized the repurchase of up to $50.0 million of the Company’s outstanding Class A Common Stock, exclusive of any fees, commissions or other expenses related to such repurchases. Repurchases could be made at the Company’s discretion in accordance with applicable securities laws from time to time in open market or private transactions. All shares repurchased will be retired. The authorization has no expiration date.

The following table presents information about repurchases and retirements of our common stock for the quarter ended December 31, 2018:

	(a)	(b)		(c)	(d)
Period	Total number of shares purchased (1)	Average price paid per share (1)		Total number of shares purchased as part of a publicly announced plan (2)	Maximum dollar amount of shares that may yet be purchased under the plan (2)
10/1/2018 to 10/31/2018	—	$	—	—	$	35,281,244
11/1/2018 to 11/30/2018	—	$	—	—	$	35,281,244
12/1/2018 to 12/31/2018	—	$	—	—	$	35,281,244
Total	—	$	—	—	$	35,281,244

_________________

(1) The Company did not purchase any shares of Class A Common Stock during the fourth quarter of 2018 under the share repurchase program approved by the Board. Information on shares repurchased from employees for personal income tax withholding on the vesting of restricted stock awards and performance-based restricted stock units is included in Part II, Item 8. During the latter part of the third quarter of 2018, we acquired 3,101,510 shares under this program at an average cost, including commissions, of $4.76 per share.

(2) On August 14, 2018, the Company announced a share repurchase program to purchase up to $50.0 million in shares of Class A Common Stock. The program does not have an expiration date.

Table of Contents

Index to Financial Statements

Item 6. Selected Financial Data

~~The~~Not ~~following information has been derived from our audited consolidated financial statements~~required.

	Successor			Predecessor
	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31,
(in thousands)							2017 (1)			2016 (1)			2015 (1)			2014 (1)
Statement of Operations Information:
Total operating revenue	$	467,977		$	47,639		$	279,369		$	101,899		$	325,363		$	213,907
Operating income (2)	(3,208,169		)	(1,777		)	36,670			(57,337		)	162,697			80,949
Income (loss) from continuing operations (2)	(3,249,347		)	(7,116		)	(12,846		)	(134,279		)	101,584			25,197
Income (loss) from discontinued operations, net of tax (3)	—			(7,746		)	(64,815		)	(33,642		)	(233,377		)	74,179
Net income (loss)	(3,249,347		)	(14,862		)	(77,661		)	(167,921		)	(131,793		)	99,200
Net loss attributable to non-controlling interest	(1,724,648		)	—			—			—			—			—
Net loss attributable to Alta Mesa Resources, Inc. Stockholders	(1,524,699		)	—			—			—			—			—
Net loss per common share attributable to Alta Mesa Resources Inc. Stockholders:
Basic	$	(8.71	)	N/A			N/A			N/A			N/A			N/A
Diluted	$	(8.71	)	N/A			N/A			N/A			N/A			N/A
Balance Sheet Information (at period end):
Cash and cash equivalents	$	26,854		$	9,070		$	3,721		$	7,185		$	8,869		$	1,349
Total assets (4)	1,357,830			1,094,685			1,085,397			813,851			722,525			911,125
Total debt, including Founder Notes (5)	864,123			624,558			635,606			556,862			743,523			785,682
Total equity	216,127			183,065			154,445			32,106			(177,049		)	(61,446		)

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

~~_________________~~The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Annual Report. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The 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 these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the Buyer’s ability and willingness to close the Sale Transactions, the volatility of oil and gas prices, production timing and volumes, our ability to continue as a going concern, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

~~(1) Our statement of operations information for prior years has been adjusted to reflect the disposal of non-STACK oil and gas assets as discontinued operations.~~19

(2) The Successor Period includes total impairment charges of $3.2 billion for oil and gas properties, other property and equipment, intangible assets, goodwill and an equity method investment. Additionally, impairment charges on oil and gas properties of $1.2 million, $0.4 million and $18.8 million, were recognized during 2017, 2016 and 2015, respectively.

(3) For the period January 1, 2018 to February 8, 2018 and 2017, 2016, 2015, and 2014, income (loss) from discontinued operations, net of tax, includes $0.9 million, $24.5 million, $41.3 million, $82.7 million, and $112.7 million, respectively, of depreciation, depletion and amortization expense. For the period January 1, 2018 to February 8, 2018 and for 2017, 2016, 2015 and 2014, income (loss) from discontinued operations, net of tax, includes impairment charges on oil and gas properties of $5.6 million, $29.1 million, $15.9 million, $158.0 million and $74.9 million, respectively. Additionally, income (loss) from discontinued operations, net of tax, for 2014 includes an $87.5 million gain on the sale of oil and gas properties.

(4) Total assets include $49.0 million, $156.7 million, $203.3 million, and $499.9 million as of December 31, 2017, 2016, 2015, and 2014, respectively, related to non-STACK assets.

(5) Prior to the Business Combination, we had notes payable to our founder (“Founder Notes”) which, at the Business Combination, were converted into an equity interest in the AM Contributor. The balance of the Founder Notes at the time of conversion was $28.3 million, including accrued interest.

Table of Contents

Index to Financial Statements

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

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the consolidated financial statements and related notes included elsewhere in this Annual Report. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The 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 these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and gas prices, production timing and volumes, our ability to continue as a going concern, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report, particularly in “Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

Alta Mesa Resources, Inc. (“AMR”), together with its consolidated subsidiaries (“we”, “us”, “our” or “the Company”), is an independent exploration and production company focused on the ~~acquisition,~~ development, ~~exploration and exploitation~~ of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. ~~We also operate in the Midstream segment through~~ Kingfisher Midstream, LLC (“KFM”) conducts our Midstream operations. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that ~~generate~~generates revenue primarily through long-term, fee-based contracts. ~~The~~ ~~KFM assets are integral to our Upstream operations, which we conduct in the same region, and they are strategically positioned to provide similar services to other producers in the area.~~

AsOn ofSeptember ~~December 31~~11, ~~2018~~2019, ~~we have a highly contiguous position of 140~~AMR,~~400~~ ~~net~~Alta ~~acres~~Mesa inand ~~the~~all ~~up-dip, naturally-fractured oil portion~~ of ~~the~~its ~~STACK~~subsidiaries ~~primarily in eastern Kingfisher and southeastern Major Counties in Oklahoma. Our drilling locations primarily target~~ (the ~~Osage,~~“AMH ~~Meramec~~Debtors” and ~~Oswego~~together ~~formations. After~~with ~~the Business Combination~~AMR, ~~we conducted development activities using a spacing array of 6 to 10 wells per section and running up to 9 rigs at~~ the ~~peak~~“Initial ~~activity~~Debtors”) ~~level.~~filed Involuntary ~~late~~petitions ~~2018,~~(“Initial ~~our~~Bankruptcy ~~production~~Petitions”) ~~across~~for ~~the~~relief ~~acreage~~under ~~evidenced~~Chapter 11 ~~that~~of the ~~well spacing was not delivering the well level production that we expected~~U. ~~During January 2019, we suspended our development program to allow our new management team to conduct a full operational and economic review~~S. WeBankruptcy ~~restarted~~Code ~~our~~(“Bankruptcy ~~development~~Code”) ~~program~~ in ~~March~~the ~~2019 with a less dense spacing pattern of up to five wells per section~~U. ~~In addition, we have worked to improve our economic returns by reducing well costs, general and administrative expense and other operating expense~~S. We ~~have~~Bankruptcy ~~operated~~Court 2for ~~rigs since restarting~~ the ~~program,~~Southern ~~however~~District ~~following the redetermination~~ of ~~the~~Texas ~~borrowing~~(“Bankruptcy ~~base of the Alta Mesa RBL in August 2019, we have decided to operate 1 rig starting in September~~Court”). ~~We will continue to evaluate how much, if any, development is appropriate going forward.~~

~~Additional~~On ~~information~~January ~~relating~~12, to2020, ~~the~~KFM ~~formation~~and all of ~~the~~its ~~Company~~subsidiaries ~~and~~(collectively, the ~~acquisition~~“KFM ofDebtors”) ~~Alta~~filed ~~Mesa~~voluntary ~~and~~petitions (“ KFM onBankruptcy ~~February~~Petitions”) 9for relief under the Bankruptcy Code. On January 13, ~~2018~~2020, ~~may~~SRII beOpco ~~found~~GP, inLLC ~~Item~~and ~~8. Immediately~~SRII ~~prior~~Opco to(collectively, the ~~Business~~“SRII ~~Combination~~Debtors” and, ~~Alta~~together ~~Mesa~~with ~~distributed~~the ~~its~~KFM ~~non-STACK~~Debtors, ~~oil~~the ~~and~~“Additional ~~gas~~Debtors”) ~~assets~~filed voluntary petitions (“SRII Bankruptcy Petitions and, ~~related~~together ~~liabilities~~with tothe ~~High~~KFM ~~Mesa~~Bankruptcy ~~Holdings~~Petitions, ~~LP (~~the “AMAdditional ~~Contributor~~Bankruptcy Petitions”) for relief under the Bankruptcy Code. We The ~~have~~Additional ~~reported~~Debtors’ ~~these~~Chapter ~~distributed~~11 ~~assets~~cases asare ~~discontinued~~being ~~operations~~jointly ~~for~~administered ~~all~~with ~~periods~~the ~~presented~~Initial Debtors’ Chapter 11 cases.

~~Pursuant~~The toInitial ~~the Business Combination, we recorded the acquired assets~~ and ~~liabilities~~Additional atDebtors operate their ~~estimated~~businesses ~~fair~~as ~~values~~“debtors-in-possession” onunder the ~~closing~~jurisdiction ~~date, including recording the fair values in the financial records~~ of ~~our respective subsidiaries. This resulted in our financial presentation being separated into two distinct periods,~~ the ~~period~~Bankruptcy ~~before~~Court ~~the Business Combination (“Predecessor Period”)~~ and ~~the~~in ~~period~~accordance ~~after~~with the ~~Business~~applicable ~~Combination~~provisions (“Successor Period”). The Company’s financial statement presentation reflects Alta Mesa as the “Predecessor” for periods prior to February 9, 2018. The Company, including the consolidated results of ~~Alta Mesa and Kingfisher, is~~ the ~~“Successor”~~Bankruptcy ~~for periods since February 9, 2018~~Code.

~~Accordingly~~On December 31, ~~for~~2019, ~~purposes~~the ofInitial ~~explaining~~Debtors ~~our~~entered ~~segment~~into ~~results~~a Purchase and Sale Agreement (as amended and restated in January 2020, wethe ~~have~~“AMH ~~presented~~PSA”) with BCE-Mach III LLC (the ~~Successor~~“Buyer”) ~~Period~~pursuant ~~and~~to which the ~~2018~~AMH ~~Predecessor~~Debtors ~~Period~~agreed ~~results~~to ofsell ~~Alta~~to ~~Mesa,~~the Buyer substantially all of our ~~Upstream~~upstream ~~segment,~~assets for an unadjusted purchase price of $232.0 million in ~~comparison~~cash, subject to ~~Alta~~customary ~~Mesa’s~~purchase ~~results~~price ofadjustments ~~operations~~(such ~~for~~transaction, ~~2017~~the ~~and~~“AMH weSale ~~have~~Transaction”). On ~~presented~~December 31, 2019, the ~~Upstream~~KFM ~~segment’s~~Debtors ~~results~~entered ~~for~~into ~~2017~~a Purchase and Sale Agreement (as amended and restated in ~~comparison~~January to2020, ~~2016. As~~the “KFM PSA” and, ~~our~~together ~~Midstream~~with ~~segment~~the AMH PSA, ~~was~~the ~~acquired~~“PSAs”) onwith ~~February~~the 9,Buyer ~~2018,~~pursuant ~~our~~to ~~discussion~~which the KFM Debtors agreed to sell to the Buyer substantially all of our ~~Midstream~~midstream assets ~~segment~~for ~~results~~an ~~covers~~unadjusted ~~only~~purchase price of $88.0 million in cash, subject to customary purchase price adjustments (such transaction, the ~~Successor~~“KFM ~~Period~~Sale Transaction” and, together with the AMH Sale Transaction, the “Sale Transactions”).

56The Sale Transactions are expected to close no later than mid-April 2020, after which we will no longer own any operating assets. Following the expected sale, we intend to provide certain transition services to the Buyer for a limited period of time and expect to wind down our remaining business during the first half of 2020, which will result in the dissolution of AMR and its subsidiaries.

In March 2020, AMR, the AMH Debtors and the SRII Debtors expect to file a Chapter 11 plan (collectively, the “AMR Plan”). The AMR Plan will generally provide for the distribution of the proceeds of the AMH Sale Transaction to AMH’s creditors and transfer any remaining assets of the Initial Debtors and SRII Opco Debtors into a liquidating trust to administer and monetize such assets and to reconcile creditor claims against such debtors for the benefit of their respective creditors. Pursuant to the AMR Plan, all outstanding shares of class A common stock and class C common stock in the Company are expected to be canceled.

The AMR Plan will be subject to approval by the Bankruptcy Court and the Initial Debtors and the SRII Debtors are expected to solicit votes on the AMR Plan from certain of their creditors entitled to vote thereon pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the AMR Plan in April 2020. To the extent that the AMR Plan is confirmed by the Bankruptcy Court, AMR expects the AMR Plan to become effective and be consummated shortly thereafter.

In March 2020, the KFM Debtors filed a Chapter 11 plan (the “KFM Plan”). The KFM Plan will generally provide for the (i) distribution of the proceeds of the KFM Sale Transaction to creditors, (ii) liquidation of any remaining assets of the KFM Debtors, and (iii) orderly wind-down of the KFM Debtors’ estates. Under the KFM Plan, the KFM Debtors will appoint a plan administr

Table of Contents

Index to Financial Statements

ator who will, among other things, oversee the wind-down of the KFM Debtors and implement all provisions of the KFM Plan, including controlling and effectuating claims reconciliation.

The KFM Plan is subject to approval by the Bankruptcy Court and the KFM Debtors are expected to solicit votes on the KFM Plan from certain of the KFM Debtors’ creditors pursuant to the requirements of the Bankruptcy Code. We expect the Bankruptcy Court to hold a hearing to consider confirmation of the KFM Plan in April 2020. To the extent that the KFM Plan is confirmed by the Bankruptcy Court, KFM expects the KFM Plan to become effective and be consummated shortly thereafter.

Additional information relating to the formation of the Company and the acquisition of Alta Mesa and KFM on February 9, 2018, may be found in Item 8. Immediately prior to the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and related liabilities to High Mesa. We have reported these distributed assets as discontinued operations for all periods presented.

Pursuant to the Business Combination, we recorded the acquired assets and liabilities at their estimated fair values on the closing date, including recording the fair values in the financial records of our respective subsidiaries. This resulted in our financial presentation being separated into two distinct periods, the period before the Business Combination (“Predecessor Period”) and the period after the Business Combination (“Successor Period”). The Company’s financial statement presentation reflects Alta Mesa as the “Predecessor” for periods prior to February 9, 2018. The Company, including the consolidated results of Alta Mesa and Kingfisher, is the “Successor” for periods since February 9, 2018.

Accordingly, for purposes of explaining our segment results, we have presented the 2019 results with the 2018 Successor Period and the 2018 Predecessor Period results of Alta Mesa, our Upstream segment. As KFM, our Midstream segment, was acquired on February 9, 2018, our discussion of our Midstream segment results covers the 2019 results and the 2018 Successor Period results.

Outlook, Market Conditions and Commodity Prices

Our revenue, ~~profitability~~ and ~~future~~profitability ~~growth rate~~ depend on many factors, particularly the prices of oil, gas and NGLs, which are beyond our control. ~~The~~Our ~~success of our~~ business ishas been significantly affected by the price of oil due to its weighting in our production profile.

Factors affecting oil prices include worldwide economic conditions; geopolitical activities in various regions of the world; worldwide supply and demand conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Commodity prices remain ~~unpredictable~~at ~~and~~depressed itlevels iscompared ~~uncertain~~to ~~whether~~past ~~the increase in market prices experienced during the first half of 2019 will be sustained. As a result~~years, wewhich ~~cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will~~ have onhad ~~our capital expenditures, production volumes or revenue. In the event that oil, gas and NGLs prices significantly decrease, such decreases could have~~ a ~~material~~negative ~~adverse~~impact ~~effect~~ on ~~our financial condition,~~ the ~~carrying~~ value of our oil and ~~natural~~ gas properties, ~~our proved reserves~~ and our ~~ability~~midstream ~~to finance operations~~assets, ~~including~~and the ~~amount~~future ofoutlook ~~the~~for ~~borrowing~~prices ~~capacity~~continues ~~under~~to ~~the~~be ~~Alta Mesa RBL~~unpredictable.

Ability to Continue as a Going ~~concern~~Concern

~~Our~~AMR’s ~~present~~only ~~level~~significant ofasset ~~indebtedness~~is ~~and~~its ~~the~~ownership ~~current~~of ~~commodity~~a ~~price~~partnership ~~environment~~interest ~~present challenges to our ability to comply with the covenants~~ in ~~the~~SRII ~~agreements governing our indebtedness~~Opco. As asuch, ~~result~~we ofhave ~~the~~no ~~decrease~~meaningful incash ~~our~~available ~~forecasted production levels compared~~ to ~~the~~meet ~~forecasts~~our atobligations ~~the~~apart ~~time~~from ofcash ~~the~~held ~~Business Combination and pressures created~~ by ~~lower~~our ~~commodity~~subsidiaries. As ~~prices,~~a inresult ~~the absence~~ of ~~one or more deleveraging transactions, we do not anticipate maintaining compliance with~~ the ~~consolidated~~bankruptcy ~~total~~filings ~~leverage~~by ~~ratio~~us ~~covenant~~and inall ~~the Alta Mesa RBL as early as the measurement date~~ of ~~September~~our 30subsidiaries, ~~2019.~~as Indescribed ~~addition~~above, wecash ~~have~~held ~~been~~by ~~substantially fully utilized under the~~ Alta Mesa ~~RBL since April 2019~~ and ~~have~~KFM nocan ~~meaningful~~only ~~remaining~~be ~~capital~~used ~~availability.~~to ~~Our~~satisfy ~~lenders exercised~~ their ~~right~~obligations to ~~conduct~~the anextent ~~optional~~authorized ~~redetermination~~by ~~ahead of~~ the ~~regularly~~Bankruptcy ~~scheduled~~Code ~~redetermination~~or inby ~~October~~order ~~2019 and have established a new borrowing base~~ of ~~$200.0~~the ~~million,~~Bankruptcy ~~effective August 13, 2019~~Court. AsThe ~~provided~~bankruptcy ~~under~~filings by the ~~Alta~~Initial ~~Mesa~~Debtors ~~RBL,~~and ~~we have elected to repay~~ the ~~excess~~Additional ~~utilization~~Debtors ~~in 5 equal monthly installments of $32.5 million~~(collectively, “the ~~first~~Debtors”) oftriggered ~~which~~defaults ~~will be due~~ in ~~September 2019. If we are unable to make these deficiency payments, we would be in default under~~ the Alta Mesa RBL~~. Our~~, ~~Board~~the ~~and~~2024 ~~its~~Notes ~~financial~~and ~~advisors are evaluating~~ the ~~available~~KFM ~~financial~~Credit ~~alternatives~~Facility, ~~including~~limiting ~~seeking~~our ~~amendments~~future orborrowing ~~waivers~~ability toand ~~the~~making ~~covenants or other provisions of~~ our ~~indebtedness~~outstanding toobligations ~~address~~immediately ~~our~~due ~~capital~~and ~~structure~~payable, ~~including~~although ~~raising new capital from~~ the ~~private~~creditors orare ~~public~~currently ~~markets~~stayed orfrom taking ~~other~~any actions ~~either~~as ina ~~court~~result ~~or out~~ of ~~court~~such defaults. The IfDebtors we are ~~unable~~also tosubject ~~reach an agreement with our lenders or find acceptable alternative financing, it may lead~~ to anlimitations ~~event~~imposed ~~of default~~ under ~~our~~Bankruptcy ~~debt~~Court ~~agreements.~~approved Ifcash ~~following~~collateral anorders ~~event~~requiring ofus ~~default,~~to ~~the~~(i) ~~Alta~~adhere ~~Mesa RBL lenders were~~ to ~~accelerate~~an ~~repayment,~~approved itbudget ~~may~~with ~~result in~~ an ~~event~~agreed-upon ofvariance ~~default~~ and an(ii) ~~acceleration~~meet ofcertain ~~the 2024 Notes~~milestones. ~~We have concluded that these circumstances create substantial doubt regarding our ability to continue as a going concern.~~

IfWe anexpect ~~agreement is reached with our creditors and we pursue a restructuring, it may be necessary for us, or our subsidiaries,~~ to ~~file~~sell asubstantially ~~voluntary~~all ~~petition for relief under Chapter 11~~ of ~~the~~our ~~U.S.~~assets ~~Bankruptcy~~no ~~Code~~later inthan ~~order~~mid-April ~~to implement the agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court~~2020. WeFollowing ~~may~~the ~~also~~expected ~~conclude~~sale, itwe isintend ~~necessary~~ to ~~initiate~~provide ~~Chapter~~certain 11transition ~~proceedings~~services to ~~implement~~the aBuyer ~~restructuring~~for ~~of our obligations even if we are otherwise unable to reach an agreement with our creditors. If~~ a ~~plan~~limited ofperiod ~~reorganization is implemented in a bankruptcy proceeding, it is possible that holders~~ of ~~claims~~time and ~~interests~~expect ~~with respect~~ to, orwind ~~rights~~down ~~to acquire,~~ our ~~equity~~remaining ~~securities~~business ~~would~~during ~~be entitled to little or no recovery, and those claims and interests may be canceled for little or no consideration. If that were to occur, we anticipate that all or substantially all of~~ the ~~value~~first ofhalf ~~all investments in our equity securities would be lost and that our equity holders would lose all or substantially all~~ of ~~their investment. It is also possible that our stakeholders~~2020, ~~including~~which ~~our secured and unsecured creditors,~~ will ~~receive~~result ~~substantially~~in ~~less than~~ the ~~amount~~dissolution of ~~their~~AMR ~~claims. For~~and aits ~~more detailed discussion, please read the Risk Factors in Item 1A~~subsidiaries.

~~Derivatives~~These factors, including historic recurring operating losses, raise substantial doubt about our ability to continue as a going concern.

~~The~~Delisting ~~objective~~from ofStock our hedging program is to produce, over time, relative revenue stability. However, in the short term, both settlements and fair value changes in our derivatives can significantly impact our results of operations, and we expect these gains and losses to continue to reflect the impact of changes in oil and gas prices. Our derivatives are reported at fair value and are sensitive to changes in the price of oil and gas. Changes in derivatives are reported as gain (loss) on derivatives, which include both the unrealized increase and decrease in their fair value, as well as the effect of realized settlements during the period. For the Successor Period, we recognized a net loss on our derivatives of $10.2 million, which includes $39.0 million in Exchange

5721

Table of Contents

Index to Financial Statements

~~cash~~As ~~settlements~~a ~~paid~~result ~~for~~of ~~derivatives~~our failure to comply with the continued listing requirements of the NASDAQ, trading in our Class A Common Stock and public warrants was suspended in September 2019, and they are now traded over the counter under the trading symbols “AMRQQ” and “AMRWQ”, respectively. ~~Our~~In ~~Alta~~February ~~Mesa~~2020, ~~RBL~~we ~~generally~~filed ~~has~~forms ~~minimum~~with the Securities and ~~maximum~~Exchange ~~hedging~~Commission ~~limits~~to deregister our Class A Common Stock and warrants under Section 12(g) of the Securities Exchange Act of 1934, as ~~further~~amended, ~~described~~(the ~~elsewhere~~“Exchange Act”) and suspend our reporting obligations under Sections 13 and 15(d) of the Exchange Act.

Derivatives

We previously operated a hedging program in accordance with requirements under the Alta Mesa RBL. Settlements and fair value changes in our derivatives had significant impacts on our results of operations. Our derivatives were reported at fair value and were sensitive to changes in the price of oil and gas. Changes in derivatives were reported as gain (loss) on derivatives, which include both the unrealized increase and decrease in their fair value, as well as the effect of realized settlements during the period.

In connection with Alta Mesa’s bankruptcy filing, we cancelled (prior to contract settlement date) all open derivative contracts in September 2019 for net proceeds of approximately $4.0 million. Proceeds received were used to make permanent repayments against our outstanding borrowings under the Alta Mesa RBL. After September 2019, we held no open derivative positions.

For 2019, we recognized a net loss on our derivatives of $11.7 million, which includes $7.6 million in cash settlements received for derivatives.

Impairments

In late fourth quarter of 2018, the combination of depressed prevailing oil and gas prices, changes to assumed spacing in conjunction with evolving views on the viability of multiple benches and reduced individual well expectations resulted in impairment charges of $2.0 billion to our proved and unproved oil and gas properties. Individual well expectations were impacted by reductions in estimated reserve recovery of original oil and gas in place. At the time of the Business Combination, we believed that the stratigraphy underlying our acreage was conducive to development of three distinct benches within the broader Mississippian section. Proved reserve assumptions at the time of the Business Combination were based on initial wells drilled in the STACK, stated expectations from other operators in the STACK as well as analogous results from other resource plays. These proved reserve assumptions included spacing of four wells per section and probable and possible resource assumptions included an incremental three wells per section for a total of seven wells per section. An incremental five wells per section (for a total of 12 wells per section) were classified as contingent resources to which no value was assigned in the purchase price allocation for the Business Combination. We expected all proved and unproved wells to deliver similar results of approximately 250 Mbbl of reserve recovery. Our 2018 drilling program was executed under these assumptions and by early 2019, we had 17 different sectional development patterns with six to ten wells per section and meaningful production results. The pattern wells generally produced as expected for the initial 60 days but began to fall below type curve after 90-120 days, which we believe was due to interference associated with the current spacing and benches. Our analysis of these results led to the following individual well reserve recovery and the overall spacing assumptions (all arrived at prior to the de-recognition of PUDs more fully described elsewhere):

•As Nonoted ~~distinct~~above, ~~benches~~the ~~exist~~Initial ~~within~~Debtors filed for bankruptcy protection in September 2019 and the ~~Mississippian~~Additional ~~section~~Debtors ~~that~~filed ~~are~~for ~~not~~bankruptcy protection in ~~direct~~January ~~communication~~2020. As ~~with~~a ~~each~~result ~~other~~of ~~resulting~~our inbankruptcy ~~only~~filings ~~four~~and previous restrictions by our lenders on our ability to ~~five~~access ~~wells~~additional ~~per~~capital, ~~section~~our ~~that~~ability to incur the levels of spending necessary to continue to develop our upstream properties and expand our midstream operations were significantly restricted. This negatively impacted our future drilling plans and our expectations regarding production levels, which contributed to lower throughput expectations for our midstream processing assets. In addition, the Sale Transactions reflect prices of $232.0 million for substantially all of the upstream properties and assets and $88.0 million for our midstream assets. As these prices were below the carrying value of the respective assets, we ~~believe~~adjusted ~~should~~our becarrying ~~spaced~~values ~~horizontally~~down 1to the expected sales prices,~~000~~ ~~feet~~after orestimated ~~more~~direct ~~apart;~~sales costs, as we believe the Buyer has the intent and ability to close the Sale Transactions.

•Additionally, ~~Year-end~~as ~~PUD~~a ~~type~~result ~~curves~~of ~~for~~the ~~future~~expected ~~development~~sales ~~are~~of ~~estimated~~our toassets ~~have~~described ~~reserves~~above and our expectations of ~~175~~contracts ~~Mbbl~~that ~~per~~will ~~well~~be rejected in bankruptcy, ~~down~~we ~~from~~also ~~the~~recognized ~~250~~impairments ~~Mbbl~~of atour ~~the~~operating ~~time~~lease right-of-use assets and a long-term prepaid asset due to our inability to recover the ~~Business~~carrying ~~Combination;~~value of these assets.

•2018 ~~Year-end proved reserve spacing per section is assumed at four or five wells per section which is roughly equivalent to the assumptions at the time of the Business Combination;~~

•In ~~Year-end~~late ~~probable~~fourth quarter of 2018, the combination of depressed prevailing oil and ~~possible~~gas ~~resource~~prices, changes to assumed spacing in conjunction with evolving views on the viability of multiple benches and reduced individual well ~~recovery~~expectations ~~was~~resulted ~~assessed~~in toimpairment becharges ~~200~~of ~~Mbbl~~$2.0 ~~compared~~billion to ~~250~~our proved ~~Mbbl~~and atunproved ~~the~~oil ~~time~~and gas properties. Individual well expectations were impacted by reductions in estimated reserve recovery of ~~the~~original ~~Business~~oil ~~Combination;~~and gas in place based on our 2018 drilling results.

•In ~~Year-end~~May ~~probable~~2018, a subsidiary of KFM entered into agreements with a third party to jointly construct and ~~possible~~operate ~~resource~~a ~~spacing~~new ~~assumes~~crude nooil ~~additional~~pipeline ~~wells~~via ~~per~~creation ~~section~~of onCimarron ~~fully~~that ~~developed~~we ~~proved~~accounted ~~sections;~~for under the equity method. Cimarron’s proposed pipeline was to extend from our processing plant to Cushing, Oklahoma and was to be constructed and operated by Cimarron, which we determined was controlled by the third-party.

•As Nothe ~~incremental~~late-2018 ~~recovery~~outlook ~~expected~~for ~~from~~Alta ~~contingent~~Mesa ~~resources~~volumes and third-party volume opportunities in the area were significantly lower than initially projected, we suspended future contributions to Cimarron and elected to abandon the project. We conducted an impairment analysis resulting in the recognition of an impairment charge of $16.0 million during the 2018 Successor Period to reduce the carrying value of our investment in Cimarron to its estimated fair value at December 31, 2018.

In May 2018, a subsidiary of KFM entered into agreements with a third party to jointly construct and operate a new crude oil pipeline via creation of Cimarron that we accounted for under the equity method. Cimarron’s proposed pipeline was to extend from our processing plant to Cushing, Oklahoma and was to be constructed and operated by Cimarron, which we determined was controlled by the non-KFM owner.22

As the outlook for Alta Mesa volumes and third-party volume opportunities in the area were significantly lower than initially projected, we suspended future contributions to Cimarron and have begun discussions to abandon the project. We do not believe the project will be completed and we conducted an impairment analysis resulting in the recognition of an impairment charge of $16.0 million during the Successor Period to reduce the carrying value of our investment in Cimarron to its estimated fair value at December 31, 2018.

Based on an estimation of the fair value of KFM utilizing an income approach that took into consideration the outlook for Alta Mesa and third-party volumes available for processing, we determined that a portion of the value of KFM’s plant and equipment and all of KFM’s intangible assets and goodwill were impaired at December 31, 2018.

The summary of impairment expense follows:

Table of Contents

Index to Financial Statements

	Successor		Predecessor
(in millions)	February 9, 2018ThroughDecember 31, 2018		January 1, 2018ThroughFebruary 8, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
Impairment attributable to:
Upstream
Unproved properties	$	742.1	$	—	$	—	$	—
Proved properties	1,291.6		—		1.2		0.4
Total Upstream	2,033.7		—		1.2		0.4
Midstream
Investment in Cimarron	16.0
Property, plant and equipment	68.4
Intangible assets	395.0		—		—		—
Goodwill	692.0		—		—		—
Total Midstream	1,171.4		—		—		—
Total impairment of assets	$	3,205.1	$	—	$	1.2	$	0.4

Based on an estimation of the fair value of KFM utilizing an income approach that took into consideration the late 2018-outlook for Alta Mesa and third-party volumes available for processing, we determined that a portion of the value of KFM’s plant and equipment and all of KFM’s intangible assets and goodwill were impaired at December 31, 2018.

~~Factors~~The ~~affecting~~summary ~~future~~of ~~performance~~impairment ~~and~~expense ~~our~~follows ~~outlook~~(there was no impairment expense during the 2018 Predecessor Period):

The primary factors affecting our production levels, which may be interrelated, are current commodity prices, capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, our wells have significant natural production declines. We attempt to overcome this natural decline primarily through development of our existing undeveloped resource, well recompletions and other enhanced recovery methods. Sustaining our production levels or our future growth will depend on our ability to continue to develop reserves. Our ability to add reserves through drilling and other development techniques is dependent on current market conditions and our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenue and, as a result, our cash flow from operations.



(in millions)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018
Impairment attributable to:
Upstream
Unproved properties	$	31.0	$	742.1
Proved properties	484.8		1,291.6
Operating lease right-of-use assets	13.3		—
Other long-term assets	27.3		—
Total Upstream	556.4		2,033.7
Midstream
Investment in Cimarron	—		16.0
Property and equipment	348.6		68.4
Operating lease right-of-use assets	0.3		—
Intangible assets	—		395.0
Goodwill	—		692.0
Total Midstream	348.9		1,171.4

Total impairment of assets	$	905.3	$	3,205.1

Results of Operations

Business Segments

Our discussion of results of operations is presented on a segment basis. Our two reportable segments are (1) Upstream and (2) Midstream, which separately feature distinct revenue producing activities. We evaluate Upstream and Midstream segment performance using Adjusted EBITDAX and Adjusted EBITDA, respectively.

The Company’s management believes Adjusted EBITDAX and Adjusted EBITDA are useful because they allow users to more effectively evaluate our operating performance, compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure and because it highlights trends in our business that may not otherwise be apparent when relying solely on GAAP measures. Adjusted EBITDAX and Adjusted EBITDA should not be considered as an alternative to our segments’ net income (loss), operating income (loss) or other performance measures derived in accordance with GAAP and may not be comparable to similarly titled measures in other companies’ reports. The Company’s applicable corporate activities have also been allocated to the supported business segments.

For the ~~Periods~~year ended December 31, 2019 compared to the periods from February 9, 2018 ~~Through~~through December 31, 2018 (2018 Successor Period) and January 1, 2018 ~~Through~~through February 8, 2018 (Predecessor) ~~Compared to the Year Ended December 31, 2017 (Predecessor~~Period)

The ~~segment~~tables ~~results~~included ~~exclude~~below set forth financial information for the year ended December 31, 2019. The 2018 Successor Period and the Predecessor Period are distinct reporting periods as a result of the Business Combination. The Predecessor Period amounts below exclude operating results related to discontinued operations. We refer to the combined 2018 Successor Period from February 9, 2018 through December 31, 2018 and ~~exclude~~the ~~inter-segment~~Predecessor ~~consolidating~~Period ~~eliminations~~from January 1, 2018 through February 8, 2018 as the “2018 Period”.

5923

Table of Contents

Index to Financial Statements

Upstream Segment Results of Operations

Our Upstream segment was impacted by the Business Combination, which caused our 2018 results to be separately presented between Successor and Predecessor Periods. In preparing the following discussion, we have provided a combined total to arrive at a full year 2018 amount and context for the change of such full year amount to the ~~2017~~2019 comparable amount. We view 2018 as a single reporting period since the impact of the Business Combination was limited to the items described below. We believe that this approach:

• allows readers of our financial statements to see how management has evaluated the operating results; and

• provides readers of our financial statements with adequate context for their analysis of our operating results~~; and~~.

• provides a better context for whether past results are indicative of future results.

The impact to our Upstream results following the Business Combination primarily relates to increased depletion expense associated with a step-up for proved oil and gas properties and to impairment expense which is associated with the step-up for both unproved and proved oil and gas properties. We do not believe that the presentation of full pro forma segment results is more preferable than the information that follows.

Table of Contents

Index to Financial Statements

Revenue

Our oil, gas and NGLs revenue varies as a result of changes in commodity prices and production volumes. The following table summarizes our revenue and production data for the periods presented:

໿

	Successor				~~Predecessor~~			Predecessor
(in thousands, except per unit data)	~~February~~Year 9,Ended ~~2018 Through~~ December 31, ~~2018~~2019			February 9, 2018ThroughDecember 31, 2018	~~January 1, 2018 Through February 8, 2018~~			~~Year~~January ~~Ended~~1, ~~December~~2018ThroughFebruary 318, ~~2017~~2018
Net production:
Oil (Mbbl)	5,~~053~~885			5,053	~~494~~			~~3,907~~494
Natural gas (MMcf)	1624,~~913~~802			16,913	~~1,609~~			131,~~972~~609
NGLs (Mbbl)	2,~~268~~760			2,268	~~151~~			~~1,277~~151
Total (MBoe)	1012,~~140~~779			10,140	~~914~~			~~7,513~~914
Average net daily production volume:
Oil (Mbbld)	1516.41			15.4	~~12.7~~			1012.7
Natural gas (MMcfd)	5167.9			51.9	~~41.2~~			3841.32
NGLs (Mbbld)	7.06			7.0	~~3.9~~			3.59
Total (MBoed)	3135.10			31.1	~~23.4~~			2023.64
Average sales prices:
Average sales prices before hedging:
Oil (per bbl)	$	6355.9979		$	$63.99	~~62.68~~		$	4962.7668
Effect of realized derivatives settlements (per bbl)	(7.35		)		(6.44		)	(0.34		)
Natural gas (per Mcf)	$	2.16		$	2.57			$	2.66
Oil, after hedging (per bbl)	$	56.64			$	56.24		$	49.42
NGLs (per bbl)	$	14.50		$	18.98			$	26.41
Percentage of unhedged realized oil price to NYMEX oil price	99		%		99		%	98		%
Natural gas (per Mcf)	$	2.57			$	2.66		$	2.70
Effect of realized derivatives settlements (per Mcf)	(0.15		)		0.94			0.49
Natural gas, after hedging (per Mcf)	$	2.42			$	3.60		$	3.19
Percentage of unhedged realized gas price to NYMEX gas price	84		%		87		%	89		%
NGLs (per bbl)	$	18.98			$	26.41		$	24.62
Effect of realized derivatives settlements (per bbl)	—				—			(1.14		)
NGLs, after hedging (per bbl)	$	18.98			$	26.41		$	23.48
Percentage of unhedged NGL price to NYMEX oil price	29		%		42		%	48		%
Revenue
Oil sales	$	~~323~~328,~~299~~386		$	$323,299	~~30,972~~		$	~~194~~30,~~423~~972
Natural gas sales	4353,~~407~~693			43,407	~~4,276~~			374,~~794~~276
NGL sales	4340,~~039~~026			43,039	~~4,000~~			314,~~445~~000
Total Upstream sales revenue	$	~~409~~422,~~745~~105		$	$409,745	~~39,248~~		$	~~263~~39,~~662~~248
Gain on sale of assets	$	1,488		$	4,751			$	840

Oil revenue for ~~the~~2019 ~~Successor~~decreased ~~Period~~compared ~~and~~to the 2018 ~~Predecessor~~ Period ~~increased~~due ~~compared~~ to ~~the~~a ~~year~~decrease ~~ended~~in ~~December~~average ~~31,~~market ~~2017~~prices ~~due~~in to2019, ~~an increase in~~which ~~production~~was inpartially ~~2018~~offset ~~and~~by ~~higher~~an ~~average~~increase ~~market~~in ~~prices~~production. The increase in production in ~~2018~~2019 was due to an increase in the number of wells drilled and new wells on production as a consequence of athe ~~sharp~~significant ~~increase in~~ 2018 capital ~~expenditures~~expenditure program.

Natural gas revenue for the Successor Period and the 2018 Predecessor Period increased compared to the year ended December 31, 2017, due to an increase in production in 2018, which was partially offset by lower average market prices.24

Table of Contents

Index to Financial Statements

NGL revenue for ~~the~~2019 ~~Successor~~decreased ~~Period~~compared ~~and~~to the 2018 ~~Predecessor~~ Period ~~increased~~due ~~compared~~ to ~~the~~a ~~year~~decrease ~~ended~~in ~~December~~average ~~31,~~market ~~2017~~prices ~~due to an increase~~ in ~~production~~2019, inwhich ~~2018,~~was partially offset by ~~lower average~~ ~~prices.~~an ~~The~~ increase in production. ~~volume~~The ~~was~~pricing reduction primarily ~~due~~relates to our ~~2018~~election ~~development~~of ~~activities. The~~the ~~pricing~~treatment ~~reduction~~of ~~primarily~~ethane ~~relates~~volumes toin ~~the~~our ~~volume~~contract ~~election,~~with ~~as described below~~KFM. Under our gathering contract with KFM, we have an ability to determine ethane recovery volumes as either ~~actual~~a ~~volumes~~fixed recovery or asat the actual levels that the plant can recover. In ~~2018~~2019, we ~~generally~~ elected to recover ethane volumes at a fixed rate until August, which had the impact of increasing the NGLs volume ~~and~~but decreasing the price received per barrel as the total sales value remained unchanged. Beginning in August 2019, we elected to recover actual ethane volumes. The increase in production volume was primarily due to our 2018 development activities.

Gain ~~(loss)~~ on sale of assets ~~in 2018~~ primarily includes agains ~~gain~~from ~~for~~ the sale of seismic data ~~totaling~~in ~~$5.1 million~~2019 inand the ~~Successor~~2018 Period.

Gain on acquisition of oil and gas properties in 2017 was related to a bargain purchase of certain proved STACK oil and gas reserves resulting in a gain totaling $1.7 million in 2017. A bargain purchase occurs when the fair value of the assets acquired, net of the fair value of liabilities assumed, exceeds the purchase price paid.



	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives:
Realized gains (losses) -
Oil	$	6,858		$	(36,505	)	$	(3,819	)
Natural gas	784			(2,456		)	1,523
Total realized gains (losses)	7,642			(38,961		)	(2,296		)
Unrealized gains (losses)	(19,386		)	28,714			8,959
Total gain (loss) on derivatives	$	(11,744	)	$	(10,247	)	$	6,663

	Successor			Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017
Gain (loss) on derivatives:
Realized gains (losses) -
Oil	$	(36,505	)	$	(3,819	)	$	(1,325	)
Natural gas	(2,456		)	1,523			6,904
NGLs	—			—			(1,462		)
Total realized gains (losses)	(38,961		)	(2,296		)	4,117
Unrealized gains (losses)	28,714			8,959			4,170
Total gain (loss) on derivatives	$	(10,247	)	$	6,663		$	8,287

Decreases and increases in future commodity prices during each period compared to futures prices in effect at the time of execution of our outstanding derivatives resulted in the gains and losses recognized, respectively, during each twelve month period.

~~Gain~~In ~~(loss)~~connection onwith ~~derivatives~~Alta ~~changes~~Mesa’s ~~represent~~bankruptcy ~~market~~filing, ~~movements~~we incancelled ~~futures~~(prior ~~prices~~to ~~compared~~contract ~~with~~settlement ~~the~~date) ~~levels~~all ~~where~~open ~~our~~derivative ~~ongoing~~contracts ~~hedging program are struck. Unrealized gains~~ in ~~the~~September ~~Successor~~2019 ~~Period~~for ~~were~~net ~~substantially~~proceeds ~~influenced by the spot and futures price declines during the latter half~~ of ~~2018,~~approximately ~~particularly~~$4.0 ~~during in the last week of December 2018~~million.

62Operating Expenses

Table of Contents

Index to Financial Statements

Operating Expenses



	Successor				Predecessor
(in thousands, except per unit data)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Operating expenses:
Lease operating	$	79,884	$	60,547	$	4,408
Transportation and marketing	70,324		50,038		3,725
Production taxes	19,455		16,865		953
Workovers	2,652		5,563		423
Exploration	52,354		34,085		7,003
Depreciation, depletion and amortization	120,617		133,554		11,670
Impairment of assets	556,427		2,033,712		—
General and administrative	59,897		114,735		21,234
Total Upstream operating expense	$	961,610	$	2,449,099	$	49,416

Select operating expenses per BOE:
Lease operating	$	6.25	$	5.97	$	4.82
Transportation and marketing	5.50		4.93		4.08
Production taxes	1.52		1.66		1.04
Workovers	0.21		0.55		0.46
Depreciation, depletion and amortization	9.44		13.17		12.77

	Successor		Predecessor
(in thousands, except per unit data)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017
Operating expenses:
Lease operating	$	60,547	$	4,408	$	43,953
Transportation and marketing	50,038		3,725		29,460
Production taxes	16,865		953		5,494
Workovers	5,563		423		4,255
Exploration	34,085		7,003		13,563
Depreciation, depletion and amortization	133,554		11,670		89,115
Impairment of assets	2,033,712		—		1,188
General and administrative	114,735		21,234		55,671
Total Upstream operating expense	$	2,449,099	$	49,416	$	242,699
Select operating expenses per BOE:
Lease operating	$	5.97	$	4.82	$	5.85
Transportation and marketing	4.93		4.08		3.92
Production taxes	1.66		1.04		0.73
Workovers	0.55		0.46		0.57
Depreciation, depletion and amortization	13.17		12.77		11.86

Lease operating expense for 2019 increased primarily due to an increase in net production coupled with the impact of additional costs for produced water disposal after our asset sale to KFM in the fourth quarter of 2018 and a non-cash charge to reduce the carrying value of certain supplies to realizable value.

~~Lease~~Transportation ~~operating~~and marketing expense for ~~the~~2019 ~~Successor~~increased ~~Period~~primarily ~~and~~due ~~the~~to ~~2018~~increase ~~Predecessor~~in ~~Period~~net ~~increased~~production. ~~compared~~The tofee ~~2017,~~we ~~primarily~~pay ~~due~~per tounit ~~cost~~reflects ~~associated~~the ~~with~~firm ~~increased~~processing ~~use~~capacity ofat ~~submersible~~the ~~pumps~~plant, as well as firm transport for ~~artificial~~our ~~lift,~~residue ~~and~~gas ~~increased~~at ~~costs~~the ~~associated~~tailgate ~~with~~of ~~our~~the ~~produced~~plant. The ~~water~~increase ~~disposal~~is ~~assets~~also ~~(prior~~due to ~~their~~an ~~sale~~increase toin ~~KFM)~~committed ~~and~~capacity ~~additional~~which ~~wells~~went ~~drilled.~~unused during 2019.

~~Transportation~~Production ~~and~~taxes ~~marketing~~for ~~expense~~2019 inincreased ~~the~~primarily ~~Predecessor~~due ~~Periods~~to ~~represents~~an ~~throughput~~increase ~~for our properties~~ in ~~the~~production ~~STACK~~volumes ~~at the KFM processing facility. Transportation~~ and ~~marketing~~an ~~expense~~increase in the ~~Successor~~Oklahoma ~~Period~~severance ~~and~~tax ~~the~~rate ~~2018~~from ~~Predecessor~~2% ~~Period increased compared~~ to ~~the year ended December 31~~5%, ~~2017,~~effective ~~primarily~~in ~~due to higher volumes flowing from our operated wells into~~ the ~~KFM~~third ~~plant.~~quarter ~~The~~of ~~fee we pay per unit reflects the firm processing capacity at the plant~~2018, ~~as well as firm transport~~ for ~~our~~wells ~~residue~~in ~~gas~~their atfirst ~~the~~3 ~~tailgate~~years of ~~the plant~~production.

~~Production~~Workovers ~~taxes~~ for ~~the~~2019 ~~Successor~~decreased ~~Period~~primarily ~~and~~due ~~2018~~to ~~Predecessor~~less ~~Period~~workover ~~are~~projects ~~higher~~undertaken asdue ~~compared~~ to ~~2017~~our ~~primarily~~efforts ~~due~~ to ~~the~~reduce ~~increase~~costs. inWorkovers ~~oil~~are ~~and~~associated ~~natural~~with ~~gas~~maintenance ~~liquids revenue~~ and another ~~increase~~efforts ~~in the Oklahoma severance tax rate from 2%~~ to ~~5%,~~increase ~~effective in the third quarter of 2018, for wells in their first 3 years of~~ production. ~~Production~~ ~~taxes are assessed based on revenues on a pre-hedge basis.~~

Successor

~~Predecessor~~

Predecessor

(in thousands)

~~February~~Year 9,Ended ~~2018 Through~~ December 31, ~~2018~~2019

February 9, 2018ThroughDecember 31, 2018

~~January 1, 2018 Through February 8, 2018~~

~~Year~~January ~~Ended~~1, ~~December~~2018ThroughFebruary 318, ~~2017~~2018

Exploration expense:

Geological and geophysical costs

61,~~755~~246

$6,755

~~2,440~~

52,~~729~~440

Exploratory dry hole expense

~~1,954~~23

1,954

—

Other exploration expense, including expired leases

2451,~~374~~010

24,374

~~4,504~~

74,~~797~~504

ARO settlements in excess of recorded liabilities

~~1,002~~75

1,002

3759

Total exploration expense

3452,~~085~~354

$34,085

~~7,003~~

137,~~563~~003

63Exploration expense for 2019 increased primarily due to an increase in expired and expiring leases, primarily for those in Major and Kingfisher counties in Oklahoma. Geological and geophysical costs decreased as a result of headcount reductions.

Table of Contents

Index to Financial Statements

~~Exploration~~Depreciation, ~~expense~~depletion ~~for~~and ~~the~~amortization ~~Successor~~expense ~~Period~~for ~~and~~2019 ~~the~~decreased ~~2018~~as ~~Predecessor~~a ~~Period~~result ~~increased~~of ~~compared~~a tosignificantly ~~2017~~lower ~~primarily~~depletable base due to animpairments ~~increase~~recorded induring ~~expired~~2018 ~~leaseholds of $20.1 million~~ and ~~a single exploratory dry hole costing $2~~2019.0 ~~million.~~

Depreciation, depletion and amortization expense was higher on a per BOE basis in the Successor Period and the 2018 Predecessor Period as compared to 2017, primarily due to an increase in capital spending and in production in relation to booked reserves for 2018 on a Boe basis.



	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
Impairment of assets:
Impairment of unproved properties	$	31,023	$	742,065	$	—
Impairment of proved properties	484,830		1,291,647		—
Impairment of operating lease right-of-use assets	13,245		—		—
Impairment of other long-term assets	27,329		—		—
Total impairment of assets	$	556,427	$	2,033,712	$	—

	Successor		Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017
Impairment of assets:
Impairment of unproved properties	$	742,065	$	—	$	—
Impairment of proved properties	1,291,647		—		1,188
Total impairment of assets	$	2,033,712	$	—	$	1,188

Impairment of assets for 2019 consisted of impairment of our proved and unproved properties, operating lease right-of-use assets and a long-term prepaid asset. Our oil and gas properties were impaired during the third quarter of 2019 based on our impairment analysis resulting from our bankruptcy filing and further impaired during the fourth quarter of 2019 after taking into consideration the expected purchase price of the AMH Sale Transaction, net of estimated direct costs, for substantially all of our upstream assets. Operating lease right-of-use assets were impaired during the second quarter 2019 based on our inability to fully recover cash outflows due to lessors for certain unused office space. A further impairment of the remaining value of our operating lease right-of-use assets, as well as significant portion of a long-term prepaid asset, was taken as of December 31, 2019, due to the expected sale of substantially all of our assets and the expected rejection of certain leases and contracts that indicated we would not be able to fully recover the carrying value of those assets. We believe the Buyer has the intent and ability to close the Sale Transactions.

For the 2018 Period, impairment largely related to a decrease in commodity prices, as well as the results of exploratory and development drilling and well performance, which reduced the value of our assets. A significant decline in spot and future estimated commodity prices late in the fourth quarter of 2018, and the impact of changes in our individual well reserve recovery estimates triggered a downward revision in the future cash flows expected to be generated by our oil and gas properties, which required us to reduce the carrying value of those properties to estimated fair value.

Impairment of assets largely hinges on a decrease in commodity prices, as well as the results of exploratory and development drilling and well performance, which reduced the value of our assets. A significant decline in spot and future estimated commodity prices late in the fourth quarter of 2018, and the impact of changes in our individual well reserve recovery estimates triggered a downward revision in the future cash flows expected to be generated by our oil and gas properties, which required us to reduce the carrying value of those properties to estimated fair value.



	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018
General and administrative expense:
Employee-related costs	$	22,018	$	18,203	$	1,032
Equity-based compensation	5,718		20,000		—
Professional fees	8,289		12,981		1,019
Strategic costs	8,116		—		—
Business Combination	—		23,717		17,040
Severance costs	4,865		8,357		—
Information technology	4,002		4,654		—
Operating leases	4,193		3,267		208
Provision for uncollectible receivables	1,218		22,438		—
Other	1,478		1,118		1,935
Total general and administrative expense	$	59,897	$	114,735	$	21,234

	Successor		Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017
General and administrative expense:
Employee-related costs	$	20,129	$	1,032	$	28,317
Strategic costs - Business Combination costs	23,717		17,040		8,118
Equity-based compensation	20,000		—		—
Professional fees	13,028		1,019		10,567
Severance costs	8,357		—		—
Provision for uncollectible related party receivables	22,438		—		—
Other	7,066		2,143		8,669
Total general and administrative expense	$	114,735	$	21,234	$	55,671

General and administrative expense for 2019 decreased compared to the 2018 Period primarily due to (i) nonrecurring expenses in the 2018 Period related to the Business Combination and professional fees for various advisors, (ii) a $22.4 million provision for certain related party receivables (including notes receivable) we assessed as uncollectible, and (iii) higher equity-based compensation expense and severance costs associated with the departure of certain members of executive management in late 2018. General and administrative expense during 2019 also included costs for legal and strategic financial advisory services associated with financial restructuring activities, including negotiations with representatives of our lenders and other third

General and administrative expense for the Successor Period and the 2018 Predecessor Period increased compared to 2017. Strategic costs and professional fees were higher in 2018 due to advisors helping to value and integrate the acquired business pursuant to the Business Combination, plus the related increase in accounting and audit professional fees. The Successor Period also includes a $22.4 million reserve associated with estimated collectibility of receivables from certain related parties (including notes receivable), equity-based compensation awards and the establishment of a stock-based compensation program, plus severance costs associated with the departure of certain members of executive management in late 2018, with no similar activity in the Predecessor Periods. Employee-related costs decreased primarily due to reduced headcount.27

Table of Contents

Index to Financial Statements

~~Below~~parties, isas well as severance costs associated with a ~~reconciliation~~reduction in force in early 2019. All professional fees incurred from the filing of ~~Upstream~~the ~~Adjusted~~Initial ~~EBITDAX~~Bankruptcy Petitions forward, and directly related to ~~loss~~the ~~from~~bankruptcy, ~~continuing~~are ~~operations~~reported ~~before~~in ~~income~~Reorganization ~~taxes:~~items, net.

	Successor			Predecessor
(in thousands)	February 9, 2018ThroughDecember 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017
Loss from continuing operations before income taxes	$	(2,076,370	)	$	(7,116	)	$	(12,840	)
Interest expense	38,265			5,511			50,585
Gain on unrealized hedges	(28,714		)	(8,959		)	(4,170		)
Loss on sale of property and equipment	388			—			—
Exploration	34,085			7,003			13,563
Depreciation, depletion and amortization	133,554			11,670			89,115
Impairment of assets	2,033,712			—			1,188
Provision for uncollectible related party receivables(1)	22,438			—			—
Equity-based compensation	20,000			—			—
Business Combination related expense	23,717			17,040			8,118
Upstream Adjusted EBITDAX	$	201,075		$	25,149		$	145,559

Below is a reconciliation of our loss from continuing operations before income taxes to Upstream Adjusted EBITDAX:



	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Loss from continuing operations before income taxes	$	(597,510	)	$	(2,076,370	)	$	(7,116	)

Interest expense	49,823			38,265			5,511
Depreciation, depletion and amortization	120,617			133,554			11,670
Exploration	52,354			34,085			7,003
Loss (gain) on unrealized hedges	19,386			(28,714		)	(8,959		)
Loss (gain) on sale of property and equipment	—			388			—
Impairment of assets	556,427			2,033,712			—
Equity-based compensation	5,718			20,000			—
Provision for uncollectible related party receivables⁽¹⁾	886			22,438			—
Severance costs	4,865			—			—
Strategic costs	8,116			—			—
Business combination	—			23,717			17,040
Non-cash lease operating expense	3,835			—			—
Reorganization items, net	(449		)	—			—
Upstream Adjusted EBITDAX	$	224,068		$	201,075		$	25,149

_________________

(1) Represents a ~~reserve~~provision ~~associated~~for ~~with~~the estimated ~~collectibility~~uncollectibility of certain related party receivables (including notes receivable) ~~and is included in general and administrative expense in the Successor Period~~.

Other (Income) Expense



	Successor						Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018
Alta Mesa RBL	$	24,541		$	2,807		$	815
2024 Notes	27,453			35,273			3,281
Bond premium amortization	(3,432		)	(4,512		)	—
Deferred financing cost amortization	195			221			171
Other	1,066			4,476			1,244
Total interest expense	49,823			38,265			5,511
Interest income	(154		)	(1,983		)	(172		)
Reorganization items, net	(449		)	—			—
Total other (income) expense, net	$	49,220		$	36,282		$	5,339

Interest expense for 2019 increased due to higher average debt balances outstanding under the Alta Mesa RBL coupled with higher default and borrowing base deficiency interest rates beginning in September 2019. We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately $12.0 million through December 31, 2019.

Table of Contents

Index to Financial Statements

Reorganization items, net



(in thousands)	Year Ended December 31, 2019
Unamortized deferred financing fees and premiums	$	(24,725	)
Terminated contracts	(1,435		)
Legal and other professional advisory fees	25,711
Reorganization items, net	$	(449	)

Midstream Segment Results of Operations

Revenue

Our Midstream revenue was primarily derived from product sales, gas gathering and processing, crude oil gathering, and produced water gathering and disposal fees.

	Successor
(in thousands)	Year Ended December 31, 2019		February 9, 2018ThroughDecember 31, 2018
(in thousands)	February 9, 2018ThroughDecember 31, 2018
Sales of gathered production	$	37,195	$	31,506
Sales of gathered production	$	31,506
Midstream revenue	84,763		63,199
Midstream revenue	68,519
Produced water disposal fees	24,988		5,320
Total Midstream sales revenue	$	100,025
Total Midstream revenue	$	146,946	$	100,025
KFM gas volumes (MMcf)	3549,~~058~~147		35,058
KFM crude oil gas volumes (Mbbls)	1,~~739~~104		1,739
KFM produced water gathering volumes (Mbbls)	525,~~320~~295		5,320

Sales of gathered production ~~were~~for ~~recognized~~2019 ~~from~~increased compared to the ~~sale~~2018 ofSuccessor ~~processed~~Period ~~residue~~due to increased oil and gas, ~~condensate~~gathering volumes and ~~NGLs~~the impact of a second cryogenic processing train commissioned in mid-2018. We process the gas on behalf of the producer and sell the resulting gas, condensate and NGLs at a market price. We Product ~~remit to the producer an agreed-upon price from the resulting~~ sales, ~~which is treated as product expense. The product sales~~ are recognized when sold to the third-party purchaser. Amounts recognized in product sales are dependent on whether we are acting in the role of a principal or agent in our contracts with our customers. We remit to the producer an agreed-upon price from the resulting sales, which is treated as product expense.

Midstream revenue ~~was~~for ~~driven~~2019 byincreased ~~gas~~compared ~~volumes~~to ~~gathered~~the ~~and~~2018 ~~processed,~~Successor ~~produced~~Period ~~water~~due ~~gathered~~to ~~and~~increased ~~disposed,~~gas ~~and~~gathering ~~crude oil~~ volumes ~~gathered~~and ~~under~~the ~~our~~impact ~~commercial~~of ~~agreements~~a ~~and~~second ~~the~~cryogenic ~~fees~~processing ~~assessed~~train ~~for~~commissioned ~~such~~in ~~services~~mid-2018. The ~~throughput~~level of ~~gas~~drilling ~~gathered~~ and ~~processed,~~well ~~crude~~completion ~~oil~~activity ~~gathered,~~of ~~and~~our ~~produced~~customers ~~water~~impacts ~~gathered~~the ~~and~~fees ~~disposed~~we isearn ~~derived~~ from the ~~level~~throughput of ~~drilling~~gas we gather and ~~well~~process ~~completion~~and ~~activity~~the volume of ~~our~~crude ~~customers~~oil we gather each period.

65Produced water disposal fees resulted from the acquisition of produced water disposal assets from Alta Mesa during the fourth quarter of 2018. The level of drilling and well completion activity of our customers impacts the amount of fees we generate from the produced water that we gather and dispose of.

Table of Contents

Index to Financial Statements

Expenses

	Successor
(in thousands)	Year Ended December 31, 2019		February 9, 2018ThroughDecember 31, 2018
(in thousands)	February 9, 2018ThroughDecember 31, 2018
Midstream operating	$	24,719	$	15,221
Midstream operating	$	15,221
Cost of sales for purchased gathered production	34,529		31,247
Cost of sales for purchased gathered production	31,247
Transportation and processing	9,659		9,911
Transportation and processing	9,911
Workovers	537		—
Depreciation, depletion and amortization	27,388
Depreciation and amortization	11,675		27,388
Impairment of assets:
Impairment of Cimarron investment	~~15,963~~—		15,963
Impairment of property, plant and equipment	68,407
Impairment of property and equipment	348,597		68,407
Impairment of intangible assets	394,999
Impairment of operating lease right-of-use assets	269		—
Impairment of goodwill	691,970
Impairment of intangible assets	—		394,999
Total Midstream impairment of assets	1,171,339
Impairment of goodwill	—		691,970
General and administrative	14,025
Total Midstream impairment of assets	348,866		1,171,339
Total operating expenses	$	1,269,131
General and administrative	35,427		14,025
Total operating expenses	$	465,412	$	1,269,131

Midstream operating expense ~~represents~~for ~~expenses~~2019 ~~incurred~~increased compared to ~~operate~~ the ~~gas~~2018 ~~gathering~~Successor ~~and~~Period ~~processing~~due ~~facilities~~to ~~and~~operating ~~the~~expenses ~~crude~~for ~~oil~~the ~~gathering and storage facilities and~~ produced water ~~gathering and~~ disposal ~~facilities,~~assets ~~which~~acquired ~~primarily~~from ~~includes~~Alta ~~company~~Mesa ~~labor~~during ~~and~~the ~~equipment~~fourth ~~rentals~~quarter ~~and~~of ~~maintenance,~~2018 and ~~expenses related to~~ the ~~produced~~impact ~~water~~of ~~assets~~higher ~~sold~~volumes ~~from~~processed, ~~the~~which ~~Upstream~~led ~~segment~~ to ~~the~~higher ~~Midstream~~variable ~~segment~~plant inoperating ~~November 2018~~costs.

Cost of sales for purchased gathered production ~~represents~~for ~~payments~~2019 increased compared to ~~producers~~the ~~for~~2018 ~~their~~Successor ~~agreed-upon~~Period ~~percent~~due to increase in sales of ~~proceeds~~gathered ~~from~~production. The ~~the~~margin ~~sale~~for ofnet ~~processed~~sales ~~gas,~~increased ~~condensate~~due ~~and~~to ~~NGLs~~plant efficiency improvements during 2019.

~~Transportation~~Depreciation and ~~processing~~amortization expense ~~includes~~for ~~compression,~~2019 ~~gathering,~~decreased ~~processing~~compared ~~and~~to ~~deficiency~~the ~~fees~~2018 ~~for~~Successor ~~third-party~~Period ~~offtakes~~due to amortization expense related to intangible customer relationship assets that were fully impaired at December 31, ~~along~~2018. This impact was coupled with ~~fees~~a ~~for~~decrease ~~unutilized~~in ~~firm~~tangible ~~transport~~asset ~~capacity~~depreciation as a result of significantly lower book asset values due to impairments recorded during 2018 and 2019, partially offset by depreciation on the produced water assets acquired in the fourth quarter of 2018.

~~Depreciation~~Impairment of assets for 2019 decreased compared to the 2018 Successor Period. During 2019, ~~depletion~~property and ~~amortization~~equipment ~~expense includes~~was ~~depreciation~~impaired onduring the ~~midstream~~third ~~facilities,~~quarter ~~gathering~~of ~~system~~2019 ~~and~~as ~~produced~~a ~~water~~result of our impairment analysis arising from the bankruptcy filing by Alta Mesa. We further impaired these assets ~~acquired~~during inthe ~~November~~fourth ~~2018~~quarter ~~and~~2019, ~~amortization~~after taking into consideration the expected purchase price of ~~customer~~the ~~contracts~~KFM Sale Transaction, net of estimated direct costs, for substantially all of our assets. We believe the Buyer has the intent and ~~relationships~~ability to close the Sale Transactions.

~~Impairment~~During ofthe ~~assets~~2018 ~~includes~~Successor Period, impairment ~~charges~~ of ~~$68.4~~assets ~~million~~consisted toof write-~~down~~downs ~~certain~~of ~~property~~our ~~and~~equity ~~equipment,~~method asinvestment ~~well~~in asCimarron, ~~$395.0~~certain ~~million~~property and ~~$699.9~~equipment ~~million~~and tofull write-~~off~~offs of the carrying amount of our intangible assets and goodwill~~, respectively, during the Successor Period~~. The fair value of the Midstream segment was negatively impacted by a significant decline in commodity prices in the fourth quarter of 2018 and the related impact on our and other producers’ future upstream operating plans. Our upstream operations contribute a significant portion of the volumetric throughput to the KFM plant. A decline in such throughput negatively impacts future expected profitability, and thus, fair value of the Midstream segment. Additionally, we reduced the carrying amount of our investment in Cimarron by $16.0 million to adjust its carrying value to fair value at December 31, 2018 as we believe completion of this project is not probable based on current transportation needs.

	Successor
(in thousands)	February 9, 2018ThroughDecember 31, 2018
General and administrative expenses:
Employee-related costs	$	8,199
Equity-based compensation	1,190
Professional fees	1,566
Other	3,070
Total general and administrative expense	$	14,025

We reduced the carrying amount of our investment in Cimarron to adjust its carrying value to fair value at December 31, 2018 due to our decision to abandon the project.

6630

Table of Contents

Index to Financial Statements

Below is a reconciliation of Midstream EBITDA to loss from continuing operations before income taxes:



(in thousands)	Year Ended December 31, 2019		February 9, 2018 Through December 31, 2018
General and administrative expenses:
Employee-related costs	$	14,569	$	8,199
Equity-based compensation	694		1,190
Professional fees	2,092		1,743
Strategic costs	11,479		10
Severance costs	2,162		—
Information technology	214		240
Operating leases	348		253
Provision for uncollectible receivable	2,310		—
Other	1,559		2,390
Total general and administrative expense	$	35,427	$	14,025

	Successor
(in thousands)	February 9, 2018ThroughDecember 31, 2018
Loss from continuing operations before income taxes	(1,174,131		)
Interest expense	5,031
Depreciation, depletion and amortization	27,388
Impairment of assets	1,171,339
Equity-based compensation	1,190
Midstream EBITDA	$	30,817

General and administrative expense for 2019 increased compared to the 2018 Successor Period primarily due to increased employee-related costs allocable to KFM, increased costs for legal and strategic financial advisory services associated with financial restructuring activities, and a provision to fully reserve a receivable from KFM’s former owner due to our assessment regarding collectibility. Moreover, following a reassessment of 2019 activity levels, we implemented a reduction in force program during 2019, which along with the departure of our Vice President and Chief Operating Officer - Midstream, resulted in severance costs during the period.

~~Consolidated~~Below ~~Results~~is a reconciliation of ~~Operations~~our loss from continuing operations before income taxes to Midstream Adjusted EBITDA:

	Successor				Predecessor
(in thousands)	Year Ended December 31, 2019			February 9, 2018ThroughDecember 31, 2018
(in thousands)	February 9, 2018 Through December 31, 2018				January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017
Loss from continuing operations before income taxes	$	(323,975	)	$	(1,174,131	)
Alta Mesa RBL	$	2,807			$	815		$	—
Interest expense	11,636			5,031
Alta Mesa Predecessor Credit Facility	—				—			7,283
Depreciation and amortization	11,675			27,388
KFM Credit Facility	5,031				—			—
Loss on sale of property and equipment	106			—
2024 Notes	35,273				3,281			39,375
Impairment of assets	348,866			1,171,339
Bond premium amortization	(4,512		)		—			—
Equity-based compensation	694			1,190
Deferred financing cost amortization	221				170			2,732
Severance costs	2,162			—
Other	4,476				1,245			1,195
Strategic costs	11,479			—
Total interest expense	43,296				5,511			50,585
Provision for uncollectible related party receivables	2,310			—
Interest income and other	(2,049		)		(172		)	(1,075		)
Gain on equity method investment	(5,503		)	—
Total other (income) expense	$	41,247			$	5,339		$	49,510
Adjusted EBITDA	$	59,450		$	30,817

Interest expense for the Successor Period and 2018 Predecessor Period decreased primarily due to amortization of bond premium of $4.5 million and lower interest on the Alta Mesa RBL due to lower average amounts outstanding as compared to the Alta Mesa Predecessor Credit Facility. 31

Table of Contents

Index to Financial Statements

Other Income (Expense)

For the Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016



(in thousands)	Year Ended December 31, 2019			February 9, 2018 Through December 31, 2018
KFM Credit Facility	$	10,728		$	3,062
Deferred financing cost amortization	463			305
Other	445			1,664
Total interest expense	11,636			5,031
Interest income	(17		)	(6		)
Equity in earnings of unconsolidated subsidiaries	(6,216		)	—
Total other (income) expense	$	5,403		$	5,025

~~The~~Interest ~~tables~~expense ~~included~~for ~~below~~2019 ~~set~~increased ~~forth~~primarily ~~financial~~due ~~information~~to ofhigher ~~our~~average ~~Predecessor~~debt ~~for~~balances ~~the~~outstanding ~~years~~under ~~ended~~the ~~December 31,~~KFM ~~2017~~Credit ~~and 2016~~Facility. ~~The~~Other ~~amounts~~interest ~~below~~primarily ~~exclude~~relates ~~operating results related~~ to ~~discontinued~~commitment ~~operations~~fees.

~~Upstream~~Equity ~~Segment~~in ~~Results~~earnings of ~~Operations~~unconsolidated subsidiaries represents our share of earnings due to our equity method investment in Cimarron. In November 2019, we obtained control of Cimarron. As a result, we recognized a gain of $5.5 million to adjust our investment to the fair value of the assets to be received upon consolidating this entity.

Revenue

	Predecessor
(in thousands, except per unit data)	Year Ended December 31, 2017			Year Ended December 31, 2016
Net production:
Oil (Mbbl)	3,907			2,571
Natural gas (MMcf)	13,972			8,259
NGLs (Mbbl)	1,277			824
Total (MBoe)	7,513			4,772
Average net daily production volume:
Oil (Mbbld)	10.7			7.0
Natural gas (MMcfd)	38.3			22.6
NGLs (Mbbld)	3.5			2.3
Total (MBoed)	20.6			13.1
Average sales prices:
Oil (per bbl)	$	49.76		$	41.15
Effect of realized derivatives settlements (per bbl)	(0.34		)	32.10
Oil, after hedging (per bbl)	$	49.42		$	73.25
Percentage of unhedged realized oil price to NYMEX oil price	98		%	95		%
Natural gas (per Mcf)	$	2.70		$	2.42
Effect of derivatives settlements (per Mcf)	0.49			0.79
Natural gas, after hedging (per Mcf)	$	3.19		$	3.21
Percentage of unhedged realized gas price to NYMEX gas price	89		%	95		%
NGLs (per bbl)	$	24.62		$	17.21
Effect of derivatives settlements (per bbl)	(1.14		)	(0.40		)
NGLs, after hedging (per bbl)	$	23.48		$	16.81
Percentage of unhedged realized NGL price to NYMEX oil price	48		%	40		%
Revenue
Oil sales	$	194,423		$	105,811
Natural gas sales	37,794			20,021
NGL sales	31,445			14,174
Total Upstream sales revenue	$	263,662		$	140,006

໿

The 2017 increase in oil revenue was primarily attributable to higher average sales prices pre-hedge as well as increased production volumes. An increase in production of 1,336 Mbbls, resulted in an approximate $55.0 million increase in oil revenue at 2016 average oil sales price. The increase in oil volumes is primarily due to new production.

Table of Contents

Index to Financial Statements

The 2017 increase in natural gas revenue was attributable to increased production volumes as well as higher prices during 2017. The increase in gas volumes is attributable to new production.

The 2017 increase in NGL revenue was primarily attributable to an increase in prices as well as increased volumes. The increase in natural gas liquid volumes is due primarily to an increase in output.

Gain on acquisition of oil and gas properties was related to a bargain purchase of certain proved STACK oil and gas reserves resulting in a gain totaling $1.7 million in 2017.

	Predecessor
(in thousands)	Year Ended December 31, 2017			Year Ended December 31, 2016
Gain (loss) on derivatives:
Realized gains (losses) -
Oil	$	(1,325	)	$	82,522
Natural gas	6,904			6,500
NGLs	(1,462		)	(333		)
Total realized gains (losses)	4,117			88,689
Unrealized gains (losses)	4,170			(129,149		)
Total gain (loss) on derivatives	$	8,287		$	(40,460	)

Operating Expenses

	Predecessor
(in thousands, except per unit data)	Year Ended December 31, 2017		Year Ended December 31, 2016
Operating expenses:
Lease operating	$	43,953	$	29,567
Transportation and marketing	29,460		11,628
Production taxes	5,494		2,765
Workovers	4,255		3,441
Exploration	13,563		17,230
Depreciation, depletion and amortization	89,115		53,755
Impairment of assets	1,188		382
General and administrative expenses	55,671		40,468
Total Upstream operating expense	$	242,699	$	159,236
Select operating expenses per BOE:
Lease operating	$	5.85	$	6.20
Transportation and marketing	3.92		2.44
Production taxes	0.73		0.58
Workovers	0.57		0.72
Depreciation, depletion and amortization	11.86		11.26

Lease operating expense increased primarily due to increased production volume and increased compression, produced water disposal, chemicals, repairs and maintenance and fuel and power totaling $12.9 million.

Transportation and marketing expense increased primarily due to increased throughput at the KFM processing facility beginning in the second quarter of 2016. In addition, the increase is due to higher transportation and marketing fees charged to provide effective gathering, efficient processing and assurance that our production will continue to flow as the activity in the basin expands at the KFM processing facility.

Table of Contents

Index to Financial Statements

Production taxes increased $3.0 million primarily due to the increase in oil and gas revenue. Ad valorem taxes remained flat year over year.

	Predecessor
(in thousands)	Year Ended December 31, 2017		Year Ended December 31, 2016
Exploration expense:
Geological and geophysical costs	$	5,729	$	9,653
Other exploration expense	7,797		7,545
ARO settlements in excess of recorded liabilities	37		32
Total exploration expense	$	13,563	$	17,230

Exploration expense decreased primarily due to decreases in seismic expenses of $4.1 million, which are reflected in geological and geophysical costs.

Depreciation, depletion and amortization expense increased due to increased production.

	Predecessor
(in thousands)	Year Ended December 31, 2017		Year Ended December 31, 2016
Impairment of assets:
Impairment of unproved properties	$	—	$	16
Impairment of proved properties	1,188		366
Total impairment of assets	$	1,188	$	382

Impairment of assets increased due to the impairment of certain developed fields resulting from downward revisions in reserves on proved properties based on lower commodity prices, and performance or development drilling results that were below expectations.

	Predecessor
(in thousands)	Year Ended December 31, 2017		Year Ended December 31, 2016
General and administrative expense:
Employee-related costs	$	28,317	$	26,226
Strategic costs - Business Combination Costs	8,118		—
Professional fees	10,567		10,577
Other	8,669		3,665
Total general and administrative expense	$	55,671	$	40,468

General and administrative expense increased primarily due to consulting and other fees directly attributable to the Business Combination plus a legal settlement of $4.7 million which is included in other G&A.

Below is a reconciliation of Upstream EBITDAX to operating income (loss):

Table of Contents

Index to Financial Statements

	Predecessor
(in thousands)	Year Ended December 31, 2017			Year Ended December 31, 2016
Loss from continuing operations before income taxes	$	(12,840	)	$	(134,279	)
Interest expense	50,585			59,675
(Gain) loss on unrealized hedges	(4,170		)	129,149
Exploration	13,563			17,230
Depreciation, depletion and amortization	89,115			53,755
Impairment of assets	1,188			382
Non-recurring Business Combination expense	8,118			—
Upstream Adjusted EBITDAX	$	145,559		$	125,912

	Predecessor
(in thousands)	Year Ended December 31, 2017			Year Ended December 31, 2016
Alta Mesa Predecessor Credit Facility	$	7,283		$	8,826
Senior term loan facility	—			9,156
2024 Notes	39,375			37,272
Deferred financing cost amortization	2,732			3,905
Other	1,195			516
Total interest expense	50,585			59,675
Interest income and other	(1,075		)	(884		)
Loss on extinguishment of debt	—			18,151
Total other (income) expense	$	49,510		$	76,942

Interest expense decreased primarily due to the interest on our senior term loan facility that was repaid in full during the fourth quarter 2016.

Loss on extinguishment of debt resale from the 2016 repurchase of our $450 million outstanding 2018 Notes for which we recognized a loss of $13.5 million, which included unamortized discount and unamortized deferred financing costs write-offs. In addition, we repaid all amounts outstanding under the senior secured term loan facility of $127.7 million, which included accrued interest and a prepayment premium of $2.5 million. We recognized a loss related to the repayment of $4.7 million, which included write-offs of unamortized deferred financing costs totaling $2.0 million.

Loss on discontinued operations relates to the loss from the distribution of non-STACK oil and gas assets and related liabilities to the AM Contributor immediately prior to the Closing Date of the Business Combination.

Liquidity and Capital Resources

Our principal requirements for capital are to fund our day-to-day operations, ~~development activities~~ and to satisfy our contractual obligations ~~related to servicing our debt and hedges~~. During ~~2018~~2019, our main sources of liquidity and capital resources came from ~~the~~ cash ~~balance~~on ~~held following the Business Combination~~hand, operating cash ~~flows~~flow ~~generated from operations~~ and borrowings under the Alta Mesa RBL and ~~the~~ KFM Credit Facility.

~~Our~~On ~~future~~September ~~drilling~~11, ~~plans and capital budgets~~2019, asthe ~~well~~Initial asDebtors ~~our~~filed ~~midstream~~for ~~customers’~~bankruptcy ~~plans~~protection, ~~are~~which ~~subject~~constituted toan ~~change~~event ~~based~~of ~~upon~~default ~~various~~under ~~factors,~~the ~~some~~Alta ofMesa ~~which~~RBL ~~are~~that ~~beyond~~accelerated ~~our~~Alta ~~control,~~Mesa’s ~~including~~obligations ~~drilling~~thereunder. Under ~~results,~~the ~~oil~~Bankruptcy ~~and gas prices~~Code, the ~~availability~~lenders ~~and~~under ~~cost~~the ofAlta ~~capital,~~Mesa ~~drilling~~RBL ~~and~~are ~~production~~stayed ~~costs,~~from ~~availability~~taking ofany ~~drilling~~action ~~services~~against ~~and~~the ~~equipment,~~AMH ~~midstream~~Debtors ~~availability,~~as ~~other~~a ~~working~~result ~~interest~~of ~~owner~~an ~~participation~~event ~~and~~of ~~regulatory matters~~default. As ~~Any deferral~~ of ~~planned~~December 31, ~~capital expenditures~~2019, ~~particularly~~we ~~with~~had ~~respect~~$355.9 tomillion ~~bringing~~in ~~new~~outstanding ~~wells~~borrowings ~~onto~~under ~~production,~~the ~~could~~Alta ~~reduce~~Mesa ~~our anticipated production~~RBL, ~~revenue~~plus ~~and~~$1.9 ~~cash~~million ~~flow,~~in ~~and~~outstanding ~~may~~letters ~~result~~of ~~in the~~ credit.

71In August 2019, our lenders elected to exercise their right to an off-cycle borrowing base redetermination, whereby they reduced our borrowing base from $370.0 million to $200.0 million. As a condition to the borrowing base reduction, we were required to make monthly installments of $32.5 million for five months, beginning in September 2019, to reduce our outstanding borrowings to the revised borrowing base. AMR and the AMH Debtors filed for bankruptcy protection prior to making any of these payments. Subsequent to Alta Mesa’s bankruptcy filing, we began operating under a cash collateral order issued by the Bankruptcy Court that allows Alta Mesa to use its cash collateral. The terms and conditions of the cash collateral order include, without limitation, adherence to a lender approved budget with an agreed upon variance and provides for certain monthly reporting obligations.

On September 23, 2019, KFM received a reservation of rights letter from its lenders asserting an event of default under the KFM Credit Agreement, thereby eliminating its ability to access capital under its revolver, pending a cure of the alleged event of default. As a result, KFM utilized cash on hand and cash flow from operations to fund required expenditures and satisfy contractual obligations during the fourth quarter 2019.

On January 12, 2020, the KFM Debtors filed for bankruptcy protection under Chapter 11 of the bankruptcy code, which constituted an event of default under the KFM Credit Facility that accelerated KFM’s obligations thereunder. Under the Bankruptcy Code, the lenders under the KFM Credit Facility are stayed from taking any action against the KFM Debtors as a result of an event of default. As of December 31, 2019, outstanding borrowings under the KFM Credit Facility totaled $224.0 million and there were no outstanding letters of credit. Subsequent to KFM’s bankruptcy filing, we began operating under a cash collateral order issued by the Bankruptcy Court that allows KFM to use its cash collateral. The terms and conditions of the cash collateral order include, without limitation, adherence to a lender approved budget with an agreed upon variance and provides for certain monthly reporting obligations.

Alta Mesa and KFM expect to sell substantially all of their assets no later than mid-April 2020 for a combined price of $320.0 million before deductions for direct costs. Following the expected sale, we intend to provide certain transition services to th

Table of Contents

Index to Financial Statements

~~expiry~~e ofBuyer ~~certain~~for ~~leases. However, because~~ a ~~large~~limited ~~percentage~~period of time and expect to wind down our ~~acreage~~remaining isbusiness ~~held~~during bythe ~~production,we~~first ~~can~~half ~~alter~~of ~~our~~2020, ~~drilling~~which ~~program~~will toresult ~~minimize~~in the ~~risk~~dissolution of ~~losing~~AMR ~~significant~~and ~~acreage~~its subsidiaries.

Although we are currently capitally constrained, we strive to maintain financial flexibility and, if available on terms we find acceptable, we may utilize the capital markets to improve our capital structure or to facilitate our development program. If our operating cash flow is materially less than anticipated and other sources of capital are not available on acceptable terms, we may decide to curtail our capital spending.

During January 2019, we received an audit report from our external reserve engineers regarding their opinion of our 2018 ending proved reserves, which included multi-year development of our proved undeveloped reserves. During April 2019, in finalizing our financial reporting for 2018, we determined that we may fail to satisfy the leverage covenant under the Alta Mesa RBL during 2019. If we were to fail the leverage covenant, access to capital under the Alta Mesa RBL would likely be impaired, thus limiting our ability to satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our future drilling locations. Thus, we did not recognize any proved undeveloped locations in the final December 31, 2018 reserve report. Should our ability to fund the required development costs improve in the future, we expect to re-recognize all or a portion of those reserves as proved.

Despite the absence of PUD locations in the 2018 reserve report, we operated 2 rigs during March through August of 2019 to develop our assets, particularly to focus on testing the spacing patterns we believe to be optimal, and to implement cost reduction strategies. Prior to the August 2019 redetermination of the Alta Mesa RBL, we anticipated drilling and bringing online approximately 60 to 65 wells during 2019 while incurring approximately $140 million to $150 million of capital expenditures related to this development program. We also expected that an additional $20 million to $30 million could be incurred for other upstream non-operated projects, leasehold costs and capitalized workover activity. We will continue to evaluate the appropriate level of development, if any, going forward. We do not expect our operating cash flow to provide sufficient proceeds to meet our 2019 capital expenditure levels and we would be required to utilize cash on hand, including proceeds from borrowings under the Alta Mesa RBL, which we drew upon in April 2019 to substantially exhaust the remaining borrowing capacity.

During April 2019, our borrowing base was reduced from $400.0 million to $370.0 million as part of the semi-annual redetermination. In addition, we drew our remaining capacity to bring our outstanding borrowings to approximately $350 million and outstanding letters of credit of $20.0 million, with approximately $86.0 million of cash on hand after completing that borrowing. As of July 31, 2019, we held $87 million in cash. We did not obtain covenant relief as part of the redetermination, but that remains an important objective for us as we strive to continue to comply with all the terms of our debt. In August 2019, the lenders exercised their option to conduct an optional redetermination, pursuant to which they established a revised borrowing base of $200.0 million, which will require us to make monthly installments of $32.5 million for five months beginning in September 2019. As a consequence of reduced operating cash flow and a lowered borrowing base, we have limited ability to obtain the capital necessary to conduct our operations at desired levels. Additionally, if we are in default under the Alta Mesa RBL, the lenders could cease making amounts available, accelerate payment of amounts outstanding or seek other remedies any of which would further limit our access to the capital necessary to fund our capital expenditures. Following the August 2019 redetermination, we have decided to operate 1 rig starting in September. We will continue to evaluate how much, if any, development is appropriate going forward.

A detailed description of our debt including the significant terms and associated requirements is found in Item 8.

Alta Mesa RBL

In connection with the consummation of the Business Combination, all indebtedness at that time under the Alta Mesa senior secured revolving credit facility was repaid in full and we entered into the Alta Mesa RBL, which provided an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base, which will be redetermined semi-annually. The Alta Mesa RBL matures on February 9, 2023. In April 2018, the borrowing base was increased to $400.0 million, which was reaffirmed by the lenders during the fourth quarter of 2018. As of December 31, 2018, in addition to $161.0 million of borrowings outstanding, we also had $21.9 million of outstanding letters of credit, leaving a total borrowing capacity of $217.1 million remaining available for future use. On April 1, 2019, the borrowing base was reduced to $370.0 million upon completion of the regularly scheduled semi-annual redetermination. During April 2019, we drew $66.5 million to consume substantially all the remaining capacity under the Alta Mesa RBL. Pursuant to an optional redetermination in August 2019, the lenders established a revised borrowing base of $200.0 million.

Table of Contents

Index to Financial Statements

The Alta Mesa RBL includes usual and customary covenants for facilities of its type and size. The covenants cover

matters such as mandatory reserve reports, the responsible operation and maintenance of properties, certifications

of compliance, required disclosures to the lenders, notices under other material instruments, and notices of sales

of oil and gas properties. It also places limitations on the incurrence of additional indebtedness, restricted

payments, distributions, investments outside of the ordinary course of business and the amount of hedges that we can put in place. We are not permitted to borrow funds if we are not in compliance with the covenants.

The Alta Mesa RBL bears interest at LIBOR plus an additional margin, based on the percentage of the borrowing base being utilized, ranging from 1.50% to 2.50%. There is also a commitment fee that ranges between 0.375% and 0.50% on the undrawn borrowing base amounts. The RBL may be prepaid without a premium. Interest on outstanding facility debt was LIBOR+2.00% at December 31, 2018.

The Alta Mesa RBL has two financial maintenance covenants (each as determined under the applicable definitions):

• A ratio of current assets to current liabilities of not less than 1.0; and

• A consolidated total leverage ratio of not more than 4.0.

During 2019, perhaps as early as the quarter ended September 30, 2019, we may be unable to satisfy the consolidated total leverage ratio and recognize the need to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements.

KFM Credit Facility

Effective May 30, 2018, KFM entered into a $300.0 million amended and restated senior secured revolving credit facility (the “KFM Credit Facility”) that replaced a prior credit facility. The KFM Credit Facility matures on May 30, 2023.

As of December 31, 2018, outstanding borrowings under the KFM Credit Facility totaled $174.0 million and there were no outstanding letters of credit, leaving a total borrowing capacity of $126.0 million remaining available for future use.

Availability under the KFM Credit Facility will be redetermined each fiscal quarter as the lesser of (1) the $300.0 million commitment under the KFM Credit Facility and (2) the maximum amount that, together with the aggregate amount of all then-outstanding consolidated funded indebtedness (other than indebtedness under the KFM Credit Facility) would result in KFM being in pro forma compliance with all applicable leverage ratios at such time.

As of July 31, we had $74 million of available borrowing capacity within our midstream credit silo, which we consider to be sufficient to carry out the contemplated capital program for 2019 and 2020. We expect to incur $40 to $50 million of capital costs during 2019 to improve our plant and to expand our gathering network.

Amendment and Waiver to the KFM Credit Facility

KFM failed to timely provide its lenders quarterly financial statements for the quarter ended December 31, 2018, and failed to provide the lenders notice in connection with its acquisition of the produced water assets from Alta Mesa, including the delivery of certain recorded instruments of transfer. In April 2019, KFM entered into an amendment and limited waiver (the “Amendment”) to the KFM Credit Facility to waive the defaults and events of default arising or resulting from those failures. The Amendment also extended the deadline for delivery of audited financial statements for 2018 and the deadline for the unaudited financial statements for the quarter ended March 31, 2019, which KFM subsequently met. Further, the Amendment adds provisions which limit the maximum amount of cash KFM can hold to $15.0 million. The Amendment also generally provides that any amendment to a material contract with an affiliate during a six-month period that causes a reduction to projected total revenue by more than 15% constitutes an event of default.

2024 Notes

Alta Mesa has $500.0 million in aggregate principal amount of ~~7.875%~~outstanding ~~senior unsecured~~ notes ~~(the~~bearing ~~“2024~~interest ~~Notes”)~~at ~~that~~7.875% ~~were~~per ~~issued~~annum, atpayable ~~par~~semi-annually byeach ~~Alta~~June 15 ~~Mesa~~ and ~~its wholly owned subsidiary Alta Mesa Finance Services Corp~~December 15. ~~during the fourth quarter of 2016.~~ The 2024 Notes ~~were~~mature ~~issued~~ in aDecember ~~private placement but were exchanged for substantially identical registered senior notes in November 2017~~2024.

73Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the 2024 Notes that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the holders of the 2024 Notes are stayed from taking any action against Alta Mesa as a result of an event of default including acceleration. We ceased accruing interest on the 2024 Notes effective upon filing of the Initial Bankruptcy Petitions as payment was unlikely to occur. Unrecorded contractual interest on the 2024 Notes was approximately $12.0 million through December 31, 2019.

Table of Contents

Index to Financial Statements

The 2024 Notes will mature in December 2024, and interest is payable semi-annually on June 15 and December 15 of each year. Alta Mesa may, from time to time, redeem certain amounts of the outstanding 2024 Notes at specified prices.

During the latter half of 2018 and into 2019, the 2024 Notes saw a substantial decrease in their trading prices. The ratings associated with the 2024 Notes also deteriorated, based on the rating agencies’ belief that an exchange for less than par value had become more likely. In March 2019, we were notified that certain noteholders had formed a group, which purported to represent a majority of the face value of the 2024 Notes. We are in discussion with the group’s financial and legal advisors and have provided them with requested information, but we cannot predict what will result from the discussions or whether they will yield a constructive deal.

The 2024 Notes include usual and customary covenants for debt of its type and size. The covenants cover matters such as the responsible operation and maintenance of properties, certificates of compliance, required disclosures to the lenders, notices under other material instruments, notices of sales of oil and gas properties and events of default. The covenants also limit our ability to incur secured debt, which may impact the quantum available to refinance our Alta Mesa RBL.

The 2024 Notes have no financial maintenance covenants.

We may from time to time seek to retire the 2024 Notes through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity, contractual restrictions and other factors.

Related Party Receivables

On September 29, 2017, Alta Mesa entered into a $1.5 million promissory note receivable with its affiliate Northwest Gas Processing, LLC, which obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bears interest, which may be paid-in-kind and added to the principal amount, at a rate of 8% per annum and matured on February 28, 2019. At December 31, ~~2018~~2019 and ~~2017~~2018, amounts due under the promissory note totaled $1.7 million ~~and $1~~.5 ~~million, respectively.~~ HMS defaulted under the terms of that promissory note when it was not paid when due on February 28, 2019, and HMS has failed to cure such default. Alta Mesa subsequently declared all amounts owing under the note immediately due and payable. Alta Mesa also has an $8.5 million promissory note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount. As of December 31, ~~2018~~2019, and ~~2017~~2018, the note receivable amounted to $11.7 million ~~and $10~~.~~8 million, respectively.~~ HMI disputes its obligations under the $1.5 million note and $8.5 million note referenced above as payable to Alta Mesa. We oppose HMI’s claims and believe HMI’s obligation under the notes to be valid assets of Alta Mesa and that the full amount is payable to Alta Mesa. We are pursuing remedies under both promissory notes and under applicable law in connection with repayment of the promissory note by HMS. We believe there is substantial doubt about HMI’s ability to make payment and honor its indemnification, which is further complicated by HMI’s filing for bankruptcy protection in January 2020. As a result of the potential conflict of interest of certain of our directors who are also controlling holders and directors of HMI, our disinterested directors will address any potential conflicts of interest with respect to this matter. As of December 31, ~~2018~~2019, we established an allowance for doubtful accounts for the promissory notes totaling $13.4 million, the expense for which is included in general and administrative expense in 2018.

Interest income on the promissory notes amounted to approximately $0.9 million, ~~$0.1 million, $0.9 million,~~ and $0.81 million for the 2018 Successor Period, and the 2018 Predecessor Period, ~~and the years ended December 31, 2017 and 2016,~~ respectively, all recorded as paid-in-kind and added to the balance due thereunder. Due to our assessment of collectability, we did not recognize interest income related to this receivable in 2019.

In connection with the Business Combination, we distributed our non-STACK oil and gas assets to a subsidiary of HMI, and certain subsidiaries of HMI agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. We also entered into a management services agreement (the “~~High~~HMI ~~Mesa~~ Agreement”) with HMI with respect to its non-STACK assets. Under the ~~High~~HMI ~~Mesa~~ Agreement, during the 180-day period following the Closing (the “Initial Term”), we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the ~~High~~HMI ~~Mesa~~ Agreement automatically renewed for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. As compensation for the Services, HMI agreed to pay us each month (i) a management fee of $10,000, (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently reached agreement to terminate the ~~High~~HMI ~~Mesa~~ Agreement effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services from Alta Mesa to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the HMI Agreement. Prior to 2018, we also incurred $0.8 million of costs for the direct benefit of HMI and the non-STACK assets, outside of the HMI Agreement, and pursuant to the HMI Agreement as “Receivables due from related party” in the balance sheets. As of December 31, 2019 and December 31, 2018, we had receivables of approximately $9.8 million and $10.1 million for costs and expenses incurred on HMI’s behalf. Subsequent to

7433

Table of Contents

Index to Financial Statements

During the transition period, HMI agreed to pay us (i) for all Services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the High Mesa Agreement. Prior to 2018, we also incurred $0.8 million of costs for the direct benefit of HMI and the nonyear-~~STACK~~end ~~assets, outside of the High Mesa Agreement, and pursuant to the High Mesa Agreement as “Receivables due from related party” in the balance sheets. As of December 31,~~ 2018 ~~(Successor) and December 31~~, ~~2017 (Predecessor),~~ we ~~had receivables of approximately $10.1 million and $0.8 million for costs and expenses incurred on HMI’s behalf. Subsequent to year-end, we~~ billed HMI $0.98 million for incremental MSA costs incurred and have received approximately $1.01 million in payments. HMI has disputed certain of these amounts billed by Alta Mesa. We are pursuing remedies under applicable law in connection with repayment of this receivable. ~~There~~We believe there is nosubstantial ~~guarantee~~doubt ~~that~~about HMI’s ~~will pay the amounts it owes. In addition, our~~ ability to ~~collect~~make ~~these~~payment ~~amounts~~and orhonor ~~future~~its ~~amounts that may become due pursuant to~~ indemnification, ~~obligations~~which ~~may~~is befurther ~~adversely~~complicated ~~impacted~~ by ~~liquidity~~HMI’s ~~and~~filing ~~solvency~~for ~~issues~~bankruptcy atprotection ~~HMI~~in January 2020. As a result, as of December 31, 2019, we have recognized an allowance for uncollectible accounts of $9.08 million to fully provide for the unremitted balance ~~and may have future allowances for amounts incurred in 2019 prior to the termination of the MSA~~. We also may be subject to liabilities for the non-STACK oil and gas assets for which we should have been indemnified. We currently cannot estimate the extent of such liabilities and expect such liabilities, if any, to be addressed in connection with our pending bankruptcy proceedings.

Tax Receivable Agreement

We are party to a Tax Receivable Agreement (“TRA”) with SRII Opco, ~~the~~High ~~AM Contributor~~Mesa, and ~~the~~ Riverstone ~~Contributor~~VI Alta Mesa Holdings, L.P. This agreement generally provides for the payment by us of 85% of the amount of any realized net cash savings, in U.S. federal, state and local income tax in periods after the Business Combination as a result of (i) certain tax basis increases resulting from the exchange of SRII Opco Common Units for AMR Class A Common Stock (or, in certain circumstances, cash) pursuant to the redemption right or our right to effect a direct exchange of SRII Opco Common Units under the SRII Opco LPA, other than such tax basis increases allocable to assets held by KFM or otherwise used in KFM’s midstream business, and (ii) interest paid or deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the TRA. Also, under the TRA, we retain the benefit of the remaining 15% of these cash savings.

As of December 31, ~~2018~~2019, there had been one exchange of SRII Common Units which would trigger a payment under the TRA. This exchange occurred in November 2018 when 2,752,312 SRII Opco Common Units then held by ~~the~~High AMMesa ~~Contributor~~ were converted into the same number of shares of AMR Class A Common Stock. We have calculated the tax basis increase resulting from this exchange, and the resulting potential future net cash savings in U.S. federal, state and local income tax, multiplied by 85% to arrive at a potential Tax Receivable Agreement liability. This amount would be due and payable by us if we actually realized these future cash tax savings. However, as of December 31, ~~2018~~2019, we have recorded a full valuation allowance on our other deferred tax assets determined in accordance with GAAP, and therefore we have not realized any savings and have not recorded a liability for such at this time. WeAs ~~are~~a ~~highly~~result ~~unlikely~~of toour ~~recognize~~bankruptcy ~~these~~filings ~~attributes~~and inthe ~~2019~~expected sale of substantially all of our assets, we do not anticipate any payments being required under the TRA.

Cash Flows

	Successor				~~Predecessor~~			Predecessor
(in thousands)	~~February~~Year 9,Ended ~~2018ThroughDecember~~December 31, ~~2018~~2019			February 9, 2018ThroughDecember 31, 2018	~~January 1, 2018ThroughFebruary 8, 2018~~			~~Year~~January ~~EndedDecember~~1, 312018ThroughFebruary 8, ~~2017~~2018			~~Year EndedDecember 31, 2016~~
Cash from operating activities	$	86143,~~809~~798		$	$86,809	~~26,336~~		$	5926,~~328~~336		$	~~131,704~~
Cash from investing activities	(~~560~~320,~~547~~329		)	(560,547	~~(37,913~~	)	)	(~~345~~37,~~876~~913		)	~~(224,298~~		)
Cash from financing activities	~~501~~244,~~205~~724			501,205	~~16,932~~			~~283~~16,~~920~~932			~~91,238~~
Net increase (decrease) In cash, cash equivalents and restricted cash	$	27,467			$	5,355		$	(2,628	)	$	(1,356	)
Net increase in cash, cash equivalents and restricted cash	$	68,193		$	27,467			$	5,355

Cash from operating activities

Cash provided by operating activities ~~(including~~during ~~operating~~2019 ~~activities~~increased ofcompared ~~discontinued~~to ~~operations) for~~ the 2018 Successor Period and the 2018 Predecessor Period ~~increased~~primarily ~~compared~~due to ~~the~~collection ~~year~~of ~~ended~~receivables, ~~December~~which were higher at December 31, ~~2017~~2018 as compared to December 31, ~~primarily~~2019 due to ~~higher~~our ~~revenue~~bankruptcy ~~inside~~filing. Additionally, ofour a2018 ~~relatively~~operating ~~fixed~~cash ~~cost~~flow ~~structure. Changes~~was inburdened ~~working~~by ~~capital~~nonrecurring ~~and~~costs ~~other~~associated ~~assets~~with ~~and~~(i) ~~liabilities~~certain ~~resulted~~administrative inservices aprovided ~~decrease~~to inHMI ~~cash~~and ofits ~~approximately~~subsidiaries ~~$67.1 million~~that ~~and~~were ~~$35.9 million~~subsequently ~~for~~determined ~~the~~to ~~Successor~~be ~~Period~~uncollectible and (ii) the ~~year~~Business ~~ended~~Combination. Partially ~~December~~offsetting ~~31,~~these ~~2017,~~factors ~~respectively. Changes~~was an increased use of cash in ~~working~~2019 ~~capital~~associated ~~and~~with ~~other~~prepayment ~~assets~~of legal and ~~liabilities~~professional ~~during~~advisor ~~the~~fees ~~2018~~relating ~~Predecessor~~to ~~Period~~our ~~resulted~~bankruptcy infiling anas ~~increase~~well inas ~~cash~~a prepayment of ~~approximately~~transportation ~~$25~~fees under a long-term customer contract.~~4 million.~~

7534

Table of Contents

Index to Financial Statements

Cash provided by operating activities (including operating activities of discontinued operations) for the year ended December 31, 2017 decreased compared the year ended December 31, 2016. The changes in our working capital accounts used $35.9 million of cash during 2017, as compared to having provided $28.1 million of additional cash in 2016.

Cash from investing activities

Cash used in investing activities ~~(including~~during ~~investing~~2019 ~~activities~~decreased ofcompared ~~discontinued~~to ~~operations) for~~ the 2018 Successor Period and the 2018 Predecessor Period, ~~increased~~primarily ~~compared~~due to ~~the~~significantly ~~year~~reduced ~~ended~~capital ~~December~~expenditures ~~31,~~resulting ~~2017,~~from ~~primarily~~the ~~due~~suspension toof ~~net~~our ~~cash~~development ~~used~~activities ~~for~~in ~~the~~conjunction ~~Business~~with ~~Combination, increased~~ Alta Mesa’s ~~capital~~bankruptcy ~~expenditures,~~filing ~~and~~in ~~KFM~~September ~~capital~~2019. The ~~expenditures~~2018 ~~made in the~~ Successor Period. ~~The~~included ~~cash~~activity ~~used~~relating into ~~investing~~the ~~activities~~Business ~~was~~Combination, ~~partially~~which ~~offset~~was byfunded through proceeds withdrawn from ~~the~~a ~~Trust~~trust ~~Account~~account inthat ~~connection~~was ~~with~~established upon the ~~Business~~initial ~~Combination~~public offering of the Company in 2017.

Cash used in investing activities (including investing activities of discontinued operations) for the year ended December 31, 2017 increased compared the year ended December 31, 2016, primarily due to increased capital expenditures and acquisitions, partially offset by proceeds from the sale of the Weeks Island field and other assets.

Cash from financing activities

Cash provided by financing activities ~~(including~~during ~~financing~~2019 ~~activities~~decreased ofcompared ~~discontinued~~to ~~operations) for~~ the 2018 Successor Period and the 2018 Predecessor Period. Our ~~increased~~ability ~~compared~~ to borrow funds during 2019 was terminated upon Alta Mesa’s bankruptcy filing in September 2019 and restrictions imposed by the ~~year~~lenders ~~ended~~under ~~December~~the ~~31,~~KFM ~~2017,~~Credit ~~primarily~~Facility due to ~~proceeds~~an ~~received~~alleged indefault. During the 2018 Successor Period, we received $400.0 million from the sale of our Class A Common Stock and warrants pursuant to a forward purchase agreement, which was partially offset by ~~capital~~deferred ~~contributions~~underwriting inpayments ~~2017~~and ~~from~~certain ~~the~~other ~~admission~~costs ofassociated ~~Riverstone~~with asthe aBusiness ~~limited~~Combination ~~partner~~plus ~~and~~repurchases ~~from~~of our ~~former~~common ~~Class B limited partner, HMI~~stock.

Cash provided by financing activities (including financing activities of discontinued operations) for the year ended December 31, 2017 increased compared the year ended December 31, 2016. During 2017, we drew down $76.4 million, net of payments, under our Predecessor Credit Facility. During 2016, we used proceeds from the issuance of the 2024 Notes, capital contributions from our Class B limited partner and borrowings under our Alta Mesa Predecessor Credit Facility to repay Predecessor senior unsecured notes, the senior secured term loan facility and our senior secured revolving credit facility.

Risk Management Activities — Commodity Derivative Instruments

~~Oil~~In ~~and~~connection ~~gas~~with ~~prices~~Alta ~~are~~Mesa’s ~~inherently~~bankruptcy ~~volatile~~filing, ~~and~~we ~~unpredictable.~~cancelled ~~Accordingly,~~(prior to ~~achieve~~contract ~~more~~settlement ~~predictable~~date) ~~cash~~all ~~flow~~open ~~and~~derivative ~~reduce~~contracts ~~our~~in ~~exposure~~September 2019 for net proceeds of approximately $4.0 million. Proceeds received were used to ~~adverse~~make ~~fluctuations~~permanent inrepayments ~~commodity~~against ~~prices,~~our weoutstanding ~~have~~borrowings ~~historically~~under ~~utilized~~the ~~commodity~~Alta ~~derivatives~~Mesa RBL. After September 2019, ~~such~~we asheld ~~swaps~~no ~~and~~open derivative positions.

Table of Contents

Index to Financial Statements

collars, to hedge price risk associated with our anticipated production and to underpin our development program. This helps reduce potential negative effects of reductions in gas prices but also reduces our ability to benefit from increases in gas prices. In certain circumstances, where we have unrealized gains in our derivative portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions.

A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

A put option has an established floor price. The buyer of that put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless.

A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.

A put option and a call option may be combined to create a collar. A collar requires the seller to pay the buyer if the settlement price is above the ceiling price and requires the buyer to pay the seller if the settlement price is below the floor price. Our commodity derivatives allow us to mitigate the potential effects of the variability in operating cash flow thereby providing increased certainty of cash flows to support our capital program and to service our debt. Our derivatives provide only partial price protection against declines in natural gas prices and partially limit our potential gains from future increases in prices. The following table summarizes our remaining derivatives.

We had the following call and put derivatives at December 31, 2018:

OIL

	Volume	Weighted		Range
Settlement Period and Type of Contract	in bbls	Average		High		Low
2019
Price Swap Contracts	182,500	$	63.03	$	63.03	$	63.03
Collar Contracts
Short Call Options	2,701,000	66.31		75.20		56.50
Long Put Options	2,883,500	53.80		62.00		50.00
Short Put Options	2,883,500	42.72		52.00		37.50
2020
Collar Contracts
Short Call Options	585,600	64.32		73.80		59.55
Long Put Options	1,537,200	55.54		62.50		50.00
Short Put Options	1,537,200	44.64		50.00		37.50

Table of Contents

Index to Financial Statements

NATURAL GAS

	Volume	Weighted		Range
Settlement Period and Type of Contract	MMBtu	Average		High		Low
2019
Price Swap Contracts	10,905,000	$	2.69	$	3.09	$	2.64
Collar Contracts
Short Call Options	4,000,000	3.31		3.75		3.17
Long Put Options	3,550,000	2.81		2.90		2.70
Short Put Options	2,425,000	2.27		2.40		2.20
2020
Collar Contracts
Short Call Options	2,275,000	3.19		3.20		3.17
Long Put Options	9,150,000	2.57		2.70		2.50
Short Put Options	9,150,000	2.07		2.20		2.00
2021
Collar Contracts
Long Put Options	2,250,000	2.65		2.65		2.65
Short Put Options	2,250,000	2.15		2.15		2.15

In those instances where contracts are identical as to time period, volume and strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table above for oil may settle against either the NYMEX index or may reflect a mix of positions settling on various combinations of benchmarks.

We had the following basis swaps at December 31, 2018:

Total Gas Volumes in MMBtu overRemaining Term(1)	Reference Price 1 (1)	Reference Price 2 (1)	Period			WeightedAverage Spread($ per MMBtu)
460,000	OneOK	NYMEX Henry Hub	Jul '19	—	Dec '19	$	(0.93	)
17,950,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '19	—	Dec '19	(0.68		)
910,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '20	—	Mar '20	(0.49		)
2,365,000	San Juan	NYMEX Henry Hub	Jan '19	—	Oct '19	(0.78		)

_________________

(1) Represents short swaps that fix the basis differentials between OneOK, Tex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2018 (in thousands):

	Year Ended December 31,
	Total		2019		2020-2021		2022-2023		Thereafter
Long-term debt	$	835,000	$	—	$	—	$	335,000	$	500,000
Interest on long-term debt (1)	322,077		59,663		119,326		103,713		39,375
Operating leases	26,945		2,819		5,762		6,145		12,219
Firm transportation contracts	186,752		19,014		36,704		36,007		95,027
Drilling rigs (2)	6,068		6,068		—		—		—
Abandonment liabilities (3)	11,552		2,079		1,755		281		7,437
Total	$	1,388,394	$	89,643	$	163,547	$	481,146	$	654,058

Table of Contents

Index to Financial Statements

_________________

(1) Interest on the outstanding balance under the Alta Mesa RBL and the KFM Credit Facility is payable quarterly; and for the 2024 Notes is payable semiannually. The weighted average rates on our outstanding borrowings as of December 31, 2018 of 6.75% and 5.41% were utilized to calculate the projected interest for our Alta Mesa RBL and KFM Credit Facility, respectively. Projected obligation amounts are based on the payment schedules for interest, and are not presented on an accrual basis.

(2) Obligations for the cost of drilling rigs are included at the gross contractual value. Due to our various working interests where the drilling rig contracts will be utilized, it is not feasible to estimate a net contractual obligation. Net payments under these contracts are accounted for as capital additions to our oil and gas properties and could be less than the gross obligation disclosed.

(3) Represents estimated discounted costs to retire and remove long-lived assets at the end of their operations.

Our contracted commitments to secure capacity on third party pipelines for transportation of our natural gas are as follows:

	Upstream	Midstream(1)	Total
2019 (MMBtu)	54,750,000	49,865,000	104,615,000
2020 (MMBtu)	54,900,000	45,750,000	100,650,000
2021 (MMBtu)	54,750,000	45,625,000	100,375,000
2022 (MMBtu)	54,750,000	40,275,000	95,025,000
2023 (MMBtu)	—	36,500,000	36,500,000
Thereafter	—	450,450,000	450,450,000

_________________

(1) Total cash payment requirements for the committed capacity are $6,778,000 in 2019, $6,116,000 each in 2020 and 2021, $5,859,000 in 2022, $5,676,000 in 2023 and $70,004,000 thereafter.

We have entered into certain firm commitments intended to secure capacity on third party pipelines for transportation of our natural gas. We currently do not utilize the full amount of our contracted capacity. However, we strive to release capacity to third parties for a fee.

Off-Balance Sheet Arrangements

As of December 31, ~~2018~~2019, other than as described below, we had no guarantees of third-party obligations~~, and our off-balance sheet obligations include our obligations under operating leases~~. Alta Mesa iswas ~~also~~ contingently liable for bonds posted in the aggregate amount of $1.3 million, primarily to cover future abandonment costs, and $211.9 million in letters of credit provided under the Alta Mesa RBL. We Upon ~~typically~~closing ~~enter~~of ~~into~~the ~~short-term~~expected ~~drilling~~Sale ~~contracts~~Transactions, ~~which~~we ~~are~~would ~~customary~~be released infrom ~~the~~these ~~oil and gas industry~~obligations. We have no other off-balance sheet arrangements that are reasonably likely to materially affect our liquidity and capital resources.

Alta Mesa and HMI are both parties to a payment and indemnity agreement with our current surety provider in connection with regulatory bonds executed onprior ~~behalf~~to ofthe ~~both~~Business ~~companies~~Combination covering STACK and non-STACK assets. The surety bonds in place ~~and~~ covered by the ~~joint~~payment and indemnity agreement for HMI non-STACK properties total approximately $15 million. The surety ~~has~~asserts ~~requested~~that ~~posting~~Alta ofMesa ~~collateral.~~is Ifjointly ~~HMI~~and ~~cannot~~severally ~~post~~liable ~~collateral~~pursuant orto ~~satisfy~~the ~~its~~payment and indemnity ~~obligations~~agreement, but Alta Mesa ~~may~~disputes bethat ~~required~~claim asserting that the Business Combination evidenced separation between the STACK and non-STACK assets thereby removing any exposure of Alta Mesa to liabilities associated with non-STACK assets. As a result of the dispute, the surety has filed liens on Alta Mesa and KFM assets in order to establish a claim against Alta Mesa in the event HMI is unable to post collateral or otherwise satisfy ~~HMI’s~~its obligations ~~associated~~ with ~~HMI~~respect to the surety bonds. The ~~covering~~closing ~~non-STACK~~of ~~assets~~the expected Sale Transactions is not expected to impact these outstanding surety bonds.

Critical Accounting Policies and Estimates

Our financial statements are prepared in accordance with GAAP. In connection with preparing our financial statements, we are required to make assumptions and estimates about future events and apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, we review the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.

Our significant accounting policies are discussed in our audited financial statements included elsewhere in this Annual Report. We believe that the following accounting estimates are those most critical to fully understanding and evaluating our reported financial results, and they require our most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain.

7935

Table of Contents

Index to Financial Statements

financial results, and they require our most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain.

Oil and Gas Reserves

Policy Description

Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In calculating cash inflows for reserves, we use an unweighted average of the preceding 12-month first-day-of-the-month prices for determination of proved reserve values and for annual proved reserve disclosures. We assume continued use of technologies with demonstrated success of yielding expected results, including the use of drilling results, well performance, well logs, seismic data, geological maps, well stimulation techniques, well test data and reservoir simulation modeling.

In calculating cash outflows for reserves, we use well costs and operating costs prevailing during the preceding year, but more heavily weighted toward recent demonstration levels, which are then held constant into future periods. Our estimates of proved reserves are determined and reassessed at least annually using available geological and reservoir data as well as production performance data. Revisions may result from changes in, among other things, reservoir performance, prices, economic conditions and governmental policies.

We limit our future development program to only those wells that we expect to be developed within five years of their initial recognition.

Judgments and Assumptions

All of our reserve information is based on estimates. Estimates of gas reserves are prepared in accordance with guidelines established by the SEC. Reservoir engineering is a subjective process of estimating recoverable underground accumulations of oil and gas. There are numerous uncertainties inherent in estimating recoverable quantities of proved oil and gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, proved reserve estimates may be different from the quantities of oil and gas that are ultimately recovered.

The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. IfWe ~~future~~have ~~significant~~used ~~revisions~~estimates ~~are necessary that reduce previously estimated reserve quantities, it could result in recognition~~ of ~~impairments,~~proved ~~such~~reserves ~~as those seen~~ in ~~2018 where our year-end reserves reduced substantially compared to reserves at~~ the ~~time~~past ~~of the Business Combination. In addition~~ to ~~using estimates of proved reserves to~~ assess for impairment, and we also rely heavily on them in the calculation of depletion expense. For example, if estimates of proved reserves decline, the depletion rate and resulting expense will increase, resulting in a decrease in net income. A decline in estimates of proved reserves ~~could~~have also ~~cause~~caused us in previous periods to perform an impairment analysis to determine whether the carrying amount of oil and gas properties exceeds fair value, which would result in an impairment charge, reducing net income.

Successful Efforts Method of Accounting for Oil and Gas Properties

Policy Description

Oil and gas producing activities are accounted for using the successful efforts method under which lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

Accounting policies include:

Unproved Properties — Costs associated with the acquisition of leases are capitalized as incurred. These costs consist of amounts incurred to obtain a mineral interest or right in a property, such as a lease, options to lease, and related broker and other fees. Properties are classified as unproved until proved reserves are recognized, at which time the related costs are transferred to proved oil and gas properties, or when leases expire or are sold.

80Proved Oil and Gas Properties — Costs incurred to lease, drill, complete and equip proved reserves are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.

Impairment — Our unproved properties consist of leasehold and other capital costs incurred for properties for which no proved reserves have been identified. In determining whether unproved property is impaired, we consider numerous factors including recent leasing activity, recent drilling results in the area, our geologists’ evaluation of the property and the remaining

Table of Contents

Index to Financial Statements

~~Proved~~lease ~~Oil~~term ~~and~~for ~~Gas~~the ~~Properties —~~property. ~~Costs~~If ~~incurred~~a topotential ~~lease,~~impairment ~~drill~~exists, ~~complete~~we develop a cash flow model based on estimated resource potential and, ~~equip~~combined ~~proved~~with ~~reserves~~a ~~are~~market ~~capitalized~~approach, estimate fair value of our properties. Our ~~All~~cash ~~costs~~flow ~~incurred~~estimates tofor ~~drill~~probable and ~~equip~~possible ~~successful~~resource ~~exploratory~~potential ~~wells,~~is ~~development~~reduced ~~wells,~~by ~~development~~additional risk-~~type~~weighting ~~stratigraphic~~factors. ~~test~~We ~~wells,~~then ~~and~~reduce ~~service~~the ~~wells,~~carrying ~~including~~amount ~~unsuccessful~~of ~~development~~unproved ~~wells~~properties, ~~are~~if ~~capitalized~~higher, to estimated fair value.

~~Impairment —~~The ~~Our~~capitalized ~~unproved~~costs ~~properties consist~~ of ~~leasehold~~proved oil and ~~other~~gas ~~capital~~properties ~~costs~~are ~~incurred~~reviewed ~~for~~at ~~properties~~least ~~for~~annually, ~~which~~or nowhenever ~~proved~~events ~~reserves~~or ~~have~~changes ~~been~~in ~~identified.~~circumstances Inindicate ~~determining~~that ~~whether~~a ~~unproved~~potential ~~property~~impairment ismay ~~impaired,~~have weoccurred. ~~consider~~The ~~numerous~~determination ~~factors~~of ~~including~~recoverability ~~recent~~is ~~leasing~~based ~~activity,~~on ~~current~~comparing ~~development~~the ~~plans,~~estimated ~~expected~~undiscounted ~~resource~~future ~~recovery,~~net ~~recent~~cash ~~drilling~~flows ~~results~~at ina producing field level or the ~~area,~~likely ~~our~~cash ~~geologists’~~flow ~~evaluation~~from sale of the ~~property~~assets ~~and~~to the ~~remaining~~carrying ~~lease~~value ~~term~~of ~~for~~ the ~~property~~assets. If athe ~~potential~~carrying ~~impairment~~amount ~~exists,~~exceeds wethe ~~develop~~estimated aundiscounted ~~cash~~future ~~flow~~net ~~model~~cash ~~based~~flows, onwe ~~estimated~~adjust ~~resource~~the ~~potential~~carrying ~~and,~~amount ~~combined~~of ~~with~~the aproperties ~~market~~to ~~approach, estimate~~ fair value. ofFor our ~~properties. Our~~proved ~~cash~~oil ~~flow estimates for probable~~ and ~~possible~~gas ~~resource~~properties, ~~potential~~we isestimate ~~reduced~~fair value by ~~additional~~discounting ~~risk-weighting factors. We then reduce~~ the ~~carrying~~projected ~~amount~~future ofcash ~~unproved~~flows ~~properties,~~at ifan ~~higher,~~appropriate torisk-adjusted ~~estimated~~discount ~~fair value~~rate.

The capitalized costs of proved oil and gas properties are reviewed at least annually, or whenever events or changes in circumstances indicate that a potential impairment may have occurred. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the carrying amount exceeds the estimated undiscounted future net cash flows, we adjust the carrying amount of the properties to fair value. For our proved oil and gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

Judgments and Assumptions

Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge.

Key assumptions used to determine the undiscounted future cash flows could include estimates of future production, timing of new wells coming on line, differentials, net estimated operating costs, anticipated capital expenditures and future commodity prices. Our discussion of the judgments inherent in reserve estimation above has information with direct bearing on the judgments surrounding our depletion calculation and impairment analysis. However, in conducting our impairment analysis, we also replace pricing assumptions with future price estimates and we include values for our probable and possible resource potential in determining fair value.

Lower net undiscounted cash flows can result in the carrying amount of our oil and gas properties exceeding the net undiscounted cash flows, which results in an impairment expense. Changes in forward commodity prices and differentials, changes in levels and timing of capital and operating expenses, and changes in production among other items can result in lower net undiscounted cash flows. Forward commodity prices can change quickly and unexpectedly which can negatively impact forward commodity prices, causing lower undiscounted net cash flows. As an example, we utilized forward commodity price estimates as of December 31, 2018, in our future net cash flow estimates. These price estimates contributed to an impairment charge of $1.3 billion being recorded during the Successor Period with respect to our proved oil and gas properties. Forward commodity price estimates increased shortly after the end of 2018. Had we been able to use mid-January 2019 forward commodity price estimates instead, our impairment charge would have decreased by approximately $100 million. Similarly, future capital and lease operating costs are uncertain and can change quickly based on regional oil and gas drilling activity, steel and other raw material prices, transportation costs and regulatory requirements, among other factors. Increased capital and lease operating costs would result in lower net undiscounted cash flows. Production estimates are determined based on field activities and future drilling plans.

Drilling and field activities require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. As such, actual results may materially differ from predicted results, which could lower production and net undiscounted cash flows.

Intangible Assets

Policy Description

In connection with the acquisition of KFM, we recorded the estimated fair value of acquired customer contracts and related customer relationships as intangible assets, which were valued using the income approach, and presented as Intangible Assets.

Table of Contents

Index to Financial Statements

These intangible assets, all of which relate to the Midstream segment, have definite lives and are subject to amortization utilizing an accelerated attrition method over their economic lives.

We assess intangible assets for impairment, together with related underlying long-lived assets, whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If required, we would recognize an impairment to reduce the carrying amount of an intangible asset to its fair value.

Judgments and Assumptions

Recoverability of the carrying amount of our intangible assets is first determined by whether cash flows at the lowest level associated with the asset or a related asset group exceeds the carrying amount of the asset or asset group. Cash flows on our contracts are generally not separable from cash flows associated with our other midstream assets, which in total comprise the related asset group. If the undiscounted cash flows of the asset group are less than carrying value of the asset group, an impairment may exist and is required to be measured by the amount that the carrying value of the intangible assets exceed the fair value of those assets.

The determination of the estimated fair value of acquired customer contracts and related customer relationships requires significant judgment in determining discounted cash flows associated with those contracts and relationships. Key assumptions include estimates of revenue associated with those contracts, the probability of renewals at the end of contractual terms, operating expenses associated with the contracts, allocated costs associated with contributory assets such as working capital, fixed assets and a trained and assembled workforce and a market participant discount rate.

Events that may indicate an impairment of intangible assets include changes in market conditions, changes in the utilization of other related assets, changes in the regulatory environment and the loss of one or more significant customers. As an example, our stock price declined significantly during the Successor Period and commodity prices dropped sharply during the fourth quarter of 2018. These factors, along with results from our 2018 drilling program, led to significant changes in our future upstream operating plans and negatively impacted future expected cash flows of KFM, which caused us to conclude that our intangible assets were fully impaired at December 31, 2018. Had our drilling results been more in line with expectations or had third parties brought more volumes on-line on our system, our impairment could have been reduced or avoided altogether.

Goodwill

Policy Description

Goodwill represents the excess of the purchase price over the estimated fair value of the identified assets and liabilities acquired. Goodwill is not amortized but is subject to periodic impairment testing at least annually, or whenever events and circumstances indicate an impairment may exist. Any identified impairment of goodwill will be recognized as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill.

Judgments and Assumptions

The allocation of the cost of each acquisition to the tangible and intangible assets acquired and liabilities assumed requires significant judgment in determining the fair value of those assets and liabilities at the time of the acquisition. Such a determination is often based on an estimate of future discounted cash flows of the business acquired or the use of other valuation techniques specific to individual groups of assets or liabilities.

Key assumptions used in estimating future discounted cash flows includes future revenue, future costs of operations, future capital spending, long-term revenue and earnings growth assumptions, highest and best use of assets acquired and a market participant discount rate. In the case of our acquisition of KFM, estimated production from our upstream oil and gas properties that dedicated their production to KFM was also key to determining the amount of estimated revenue of the business acquired.

Once the fair value of the assets acquired and liabilities assumed have been determined, any residual difference is allocated to goodwill to arrive at the total purchase consideration. Goodwill is then assigned to a reporting unit for purposes of evaluating future impairment.

In periods subsequent to the acquisition, we are required to at least annually determine if the fair value of the business acquired is in excess of its current carrying value. If not, goodwill would be impaired for the difference between carrying value and fair value, to the extent of the amount of recorded goodwill. In assessing whether impairment indicators exist, we evaluate changes

Table of Contents

Index to Financial Statements

in market conditions, changes in the expected utilization of the assets acquired, changes in the regulatory environment or the loss of significant customers, among other considerations. Determination of the fair value of the business is generally based on an estimate of future discounted cash flows involving key assumptions as described above.

As noted above under “Intangible Assets”, a number of factors occurred during the Successor Period and in the fourth quarter of 2018 that led to significant changes in our future upstream operating plans and negatively impacted future expected cash flows of KFM, which caused us to conclude that the goodwill associated with our acquisition of KFM was fully impaired at December 31, 2018.

Derivatives

Policy Description

We measure our derivatives at estimated fair value and record them as assets or liabilities in the balance sheet. Changes in fair value of our derivatives are recognized as “Gain (loss) on derivatives” in the statement of operations, along with realized gains or losses from the settlement of matured derivatives.

We net the value of our derivative assets and liabilities with the same counterparty for purposes of presentation in our consolidated balance sheets where master netting agreements are in place.

Judgments and Assumptions

We have chosen not to elect hedge accounting treatment for our derivatives, which results in all changes in fair value of our derivatives being recognized each period in our statement of operations. Had we elected to treat some or all of our derivatives as cash flow hedges, any change in fair value of the derivative that effectively offsets the change in fair value of the underlying transaction, would have been deferred in other comprehensive income until the underlying transaction affected earnings at which time the offsetting impact of the hedge would have been reclassified from other comprehensive income to earnings. Hedge ineffectiveness would have been recognized in earnings each period under this election.

The estimates of the fair values of our commodity derivatives require substantial judgment. Valuations are based upon multiple factors such as futures prices, volatility data, length of time to maturity, credit risks and interest rates. We compare our estimates of fair value for these instruments with valuations obtained from independent third parties and counterparty valuation confirmations. We also make evaluations around the creditworthiness of counterparties where our derivatives are in the money. The values we report in our financial statements change as these estimates are revised to reflect actual results. Future changes to forecasted or realized commodity prices could result in significantly different values and realized cash flows for such instruments.

Recent Accounting Pronouncements

Our audited financial statements in Item 8 contain a description of recent accounting pronouncements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

WeNot ~~are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business~~required. We may enter into derivatives to manage or reduce market risk, but we do not enter into derivatives for speculative purposes. The Alta Mesa RBL also has mandatory minimum hedging requirements. We do not designate these derivatives as hedges for accounting purposes.

~~Commodity Price Risk and Hedges~~37

Our major market risk exposure is to prices for oil, gas and NGLs, which have historically been volatile. As such, future results are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional prices for gas. We have used, and expect to continue to use, derivatives to reduce our exposure to the risks of price changes. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against low prices and price volatility associated with developed and undeveloped reserves.

Table of Contents

Index to Financial Statements

Forecasted production from proved reserves is estimated in our December 2018 reserve report using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in the report, perhaps materially. Our risk factors in Item 1A contain discussions of significant matters related to future production.

The fair value of our oil and gas derivatives and basis swaps at December 31, 2018 was a net asset of $17.5 million. A 10% increase or decrease in oil and gas prices with all other factors held constant would result in an unrealized loss or gain, respectively, in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and gas commodity contracts of approximately $14.9 million (decrease in value) or $14.2 million (increase in value), respectively, as of December 31, 2018.

Counterparty and Customer Credit Risk

Our derivatives expose us to credit risk in the event of nonperformance by counterparties. While we do not require them to post collateral, we do monitor the credit standing of such counterparties, all of which have investment grade ratings.

Our principal ongoing exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and gas production. The inability or failure of our customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our purchasers of production and other working interest owners is high.

Much of our oil and gas production in 2018, including certain processed gas and NGLs, was sold through a marketing agreement with ARM Energy Management, LLC (“ARM”), who marketed and sold our oil and gas production and processed products under short-term contracts, generally with month-to-month pricing based on published indices, adjusted for transportation, location and quality. ARM generally remitted monthly collections of these sales to us, net of its fee. For the Successor Period, ARM marketed $336.2 million, or 71% of our total operating revenue for the period. We are significantly exposed to ARM’s credit quality but have experienced no losses to date.

Effective as of June 1, 2019, we have terminated our oil and NGL marketing agreement with ARM and will market such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019. With respect to gas sales, ARM continues to collect payments from purchasers, deducts their marketing fee and remits the balance to us.

Joint operations receivables arise from billings to entities that own interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

Interest Rates

We are subject to interest rate risk on our long-term fixed interest rate debt and variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivatives. A 1% increase in interest rates would increase interest expense on the KFM Credit Facility by approximately $1.7 million and would increase interest expense on the Alta Mesa RBL by approximately $1.6 million, based on the balances outstanding at December 31, 2018.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the Successor Period, the 2018 Predecessor Period or the year ended December 31, 2017. Although the impact of inflation has been insignificant in recent years, it could cause upward pressure on the cost of oilfield services, equipment and general and administrative expenses.

Table of Contents

Index to Financial Statements

Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

	Page
Audited Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firms	88
Report of Independent Registered Public Accounting Firm	39
Consolidated Statements of Operations	9040
Consolidated Balance Sheets	9141
Consolidated Statements of Cash Flows	9343
Consolidated Statement of Changes in Stockholders’ Equity	94
Consolidated Statements of Changes in Stockholders’ Equity	44
Consolidated Statements of Changes in Partners’ Capital	95
Consolidated Statement of Changes in Partners’ Capital	45
Notes to Consolidated Financial Statements	9646
Note 1 — Description of Business	9646
Note 2 — Summary of Significant Accounting Policies	9647
Note 3 — Adoption of New Standard - Revenue from Contracts with Customers	107
Note 3 — Chapter 11 Proceedings	57
Note 4 — Impairment of Assets	~~108~~62
Note 5 — Receivables	109
Note 5 — Adoption of ASU No. 2016-02, Leases	63
Note 6 — Earnings Per Share	110
Note 6 — Receivables	65
Note 7 — Supplemental Cash Flow Information	111
Note 7 — Earnings Per Share	67
Note 8 — Significant Acquisitions and Divestitures	111
Note 8 — Supplemental Cash Flow Information	68
Note 9 — Property, Plant and Equipment	118
Note 9 — Significant Acquisitions and Divestitures	68
Note 10 — Discontinued Operations (Predecessor)	118
Note 10 — Property and Equipment	71
Note 11 — Fair Value Measurements	120
Note 11 — Discontinued Operations (Predecessor)	71
Note 12 — Derivatives	121
Note 12 — Fair Value Measurements	72
Note 13 — Intangible Assets	124
Note 13 — Derivatives	73
Note 14 — Equity Method Investment	124
Note 14 — Intangible Assets	74
Note 15 — Asset Retirement Obligations	125
Note 15 — Equity Method Investment	74
Note 16 — Long-Term Debt, Net	125
Note 16 — Asset Retirement Obligations	75
Note 17 — Accounts Payable and Accrued Liabilities	128
Note 17 — Long-Term Debt, Net	75
Note 18 — Commitments and Contingencies	128
Note 18 — Accounts Payable and Accrued Liabilities	78
Note 19 — Employee Benefit Plans	131
Note 19 — Commitments and Contingencies	78
Note 20 — Significant Concentrations, Risks and Uncertainties	131
Note 20 — Employee Benefit Plans	80
Note 21 — Stockholders’ Equity and Partners’ Capital	132
Note 21 — Significant Concentrations	81
Note 22 — Equity-Based Compensation (Successor)	134
Note 22 — Stockholders’ Equity and Partners’ Capital	81
Note 23 — Income Taxes	136
Note 23 — Equity-Based Compensation (Successor)	83
Note 24 — Related Party Transactions	138
Note 24 — Income Taxes	86
Note 25 — Business Segment Information	140
Note 25 — Related Party Transactions	87
Note 26 — Subsequent Events	142
Note 26 — Business Segment Information	89
Note 27 — Supplemental Quarterly Information (Unaudited)	143
Note 27 — Supplemental Oil and Natural Gas Disclosures (Unaudited)	91
Note 28 — Supplemental Oil and Natural Gas Disclosures (Unaudited)	144

8538

Table of Contents

Index to Financial Statements

~~REPORT~~Report OFof ~~INDEPENDENT~~Independent ~~REGISTERED~~Registered ~~PUBLIC~~Public ~~ACCOUNTING~~Accounting ~~FIRM~~Firm

To the Stockholders and Board of Directors

Alta Mesa Resources, Inc.:

Opinion on Internal Control Over Financial Reporting

We have audited Alta Mesa Resources, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, because of the effect of the material weaknesses, described below, on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2018 the related consolidated statements of operations, changes in stockholders’ equity (Successor), changes in partners’ capital (Predecessor), and cash flows for the period from January 1, 2018 to February 8, 2018 (Predecessor) and for the period from February 9, 2018 to December 31, 2018 (Successor), and the related notes (collectively, the consolidated financial statements), and our report dated August 26, 2019 expressed an unqualified opinion on those consolidated financial statements.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weaknesses have been identified and included in management’s assessment:

Control Environment

• Insufficient internal resources with appropriate knowledge and expertise to design and implement, document and operate effective financial reporting processes and internal controls

• Insufficient training of personnel on the COSO 2013 Framework and its implications on financial reporting and their related internal control roles and responsibilities

• Ineffective assignment of personnel with sufficient experience to review information provided to third-party business valuation and technical accounting specialists and monitor the activities performed by them

• Ineffective policies and procedures that held personnel accountable for defined internal control responsibilities through performance measurement plans and goals

Risk Assessment

• Ineffective continuous risk assessment process to identify and evaluate the risk of misstatement due to error in recurring and nonrecurring financial reporting processes and to establish controls to mitigate those risks

• Ineffective identification and assessment of risk of misstatement due to error resulting from changes in operations affecting financial reporting and internal control over both recurring and nonrecurring transactions

Information and Communication

• Ineffective controls over the identification and processing of relevant and reliable information

• Ineffective internal communication of such information on a timely basis to personnel responsible for financial reporting, and to those charged with governance

Monitoring Activities

• Ineffective monitoring activities across the Company to ensure that the processes and internal controls related to the five COSO 2013 Framework components and underlying principles were present and functioning

• Ineffective identification and timely remediation of control deficiencies

Control Activities

• Ineffective control activities over both recurring and nonrecurring transactions including the Business Combination

• Ineffective written policies and procedures at a sufficient level of detail to affect the design and evidence the consistent and timely operation of the controls

Table of Contents

Index to Financial Statements

• Ineffective controls over the financial statement close and disclosure process, including the completeness, existence and accuracy of the financial information

• Ineffective user access information technology (IT) controls to production volumes application and data base and payroll application and ineffective automated controls and manual controls that are dependent upon the completeness and accuracy of information derived from these IT applications

• Ineffective controls over the use of certain spreadsheets

• Ineffective management review controls over various complex accounting estimates

The material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2018 consolidated financial statements, and this report does not affect our report on those consolidated financial statements. The Company acquired Kingfisher Midstream, LLC during 2018, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018, Kingfisher Midstream LLC’s internal control over financial reporting associated with total assets of 32% and operating revenue of 12% of the successor period. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Kingfisher Midstream, LLC.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on ICFR. 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 of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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/ KPMG LLP

Houston, Texas

August 26, 2019

Table of Contents

Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors

Alta Mesa Resources, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Alta Mesa Resources, Inc. and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in stockholders’ equity (Successor), changes in partners’ capital (Predecessor) and cash flows for the year ended December 31, 2019, the period from ~~January 1~~February 9, 2018 to ~~February 8~~December 31, 2018 (~~Predecessor~~Successor), and the period from ~~February 9~~January 1, 2018 to ~~December 31~~February 8, 2018 (~~Successor~~Predecessor), and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for the year ended December 31, 2019, the period from ~~January 1~~February 9, 2018 to ~~February 8~~December 31, 2018 (~~Predecessor~~Successor) , and ~~for~~ the period from ~~February 9~~January 1, 2018 to ~~December 31~~February 8, 2018 (~~Successor~~Predecessor), in conformity with U.S. generally accepted accounting principles.

We also have 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission”, and our report dated August 26, 2019 expressed an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has suffered recurring losses from operations, and isits ~~facing~~liquidity outlook, along with the risks and uncertainties ~~surrounding~~related to its ~~credit~~Chapter ~~facility~~11 ~~covenant~~voluntary ~~compliance~~petition, ~~that~~ raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 consolidated 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 consolidated 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 consolidated~~ 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 ~~consolidated~~ 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 consolidated 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 consolidated 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 consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 2018.

Houston, Texas

~~August~~March 265, ~~2019~~2020

8839

Table of Contents

Index to Financial Statements

~~REPORT~~ALTA OFMESA ~~INDEPENDENT~~RESOURCES, ~~REGISTERED~~INC. ~~PUBLIC ACCOUNTING FIRM~~(Debtor-in-possession)

Stockholders and Board of Directors

Alta Mesa Resources, Inc.

Houston, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Alta Mesa Holdings, LP, the predecessor to Alta Mesa Resources, Inc., (the “Company”) as of December 31, 2017, the related consolidated statements of operations, changes in partners’ capital, and cash flows for each of the two years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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.

/s/ BDO USA, LLP

We served as the Company’s auditor from 2014 to 2018.

Houston, Texas

March 29, 2018, except for Note 10, as to which the date is May 17, 2019

Table of Contents

Index to Financial Statements

ALTA MESA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Successor				~~Predecessor~~			Predecessor
	February 9, 2018ThroughDecember 31, 2018				January 1, 2018ThroughFebruary 8, 2018			Year EndedDecember 31, 2017			Year EndedDecember 31, 2016
	Year Ended December 31, 2019			February 9, 2018ThroughDecember 31, 2018				January 1, 2018ThroughFebruary 8, 2018
Revenue
Oil	$	~~323~~328,~~299~~386		$	$323,299	~~30,972~~		$	~~194~~30,~~423~~972		$	~~105,811~~
Natural gas	4353,~~407~~693			43,407	~~4,276~~			374,~~794~~276			~~20,021~~
Natural gas liquids	4340,~~039~~026			43,039	~~4,000~~			314,~~445~~000			~~14,174~~
Sales of gathered production	3137,~~506~~195			31,506	—			—			—
Midstream revenue	2730,~~460~~590			27,460	—			—			—
Other	410,~~762~~330			4,762	~~888~~			~~5,724~~888			~~2,350~~
Operating revenue	~~473~~500,~~473~~220			473,473	~~40,136~~			~~269~~40,~~386~~136			~~142,356~~
Gain on sale of assets	41,~~751~~382			4,751	~~840~~			28840			3
Gain on acquisitions of oil and gas properties	—				—			1,668			—
Gain (loss) on derivatives	(11,744		)	(10,247		)		6,663
Gain (loss) on derivatives	(10,247		)		6,663			8,287			(40,460		)
Total revenue	489,858			467,977				47,639
Total revenue	467,977				47,639			279,369			101,899
Operating expenses
Operating expenses
Lease operating	63,755			56,827				4,408
Lease operating	56,827				4,408			43,953			29,567
Transportation, processing and marketing	21,042			19,293				3,725
Transportation, processing and marketing	19,293				3,725			29,460			11,628
Midstream operating	24,719			15,221				—
Midstream operating	15,221				—			—			—
Cost of sales for purchased gathered production	34,529			31,247				—
Cost of sales for purchased gathered production	31,247				—			—			—
Production taxes	19,455			16,865				953
Production taxes	16,865				953			5,494			2,765
Workovers	3,189			5,563				423
Workovers	5,563				423			4,255			3,441
Exploration	52,354			34,085				7,003
Exploration	34,085				7,003			13,563			17,230
Depreciation, depletion and amortization	132,292			160,942				11,670
Depreciation, depletion and amortization	160,942				11,670			89,115			53,755
Impairment of assets	905,293			3,205,051				—
Impairment of assets	3,205,051				—			1,188			382
General and administrative	107,655			131,052				21,234
General and administrative	131,052				21,234			55,671			40,468
Total operating expenses	1,364,283			3,676,146				49,416
Total operating expenses	3,676,146				49,416			242,699			159,236
Operating income	(874,425		)	(3,208,169		)		(1,777		)
Operating income	(3,208,169		)		(1,777		)	36,670			(57,337		)
Other income (expense)
Other income (expense)
Interest expense	(61,459		)	(43,296		)		(5,511		)
Interest expense	(43,296		)		(5,511		)	(50,585		)	(59,675		)
Interest income and other	243			2,049				172
Interest income and other	2,049				172			1,075			884
Equity in earnings of unconsolidated subsidiaries	6,216			—				—
Loss on debt extinguishment	—				—			—			(18,151		)
Reorganization items, net	(197		)	—				—
Total other income (expense), net	(4155,~~247~~197		)	(41,247	~~(5,339~~	)	)	(495,~~510~~339		)	~~(76,942~~		)
Loss from continuing operations before income taxes	(3929,~~249,416~~622		)	(3,249,416	~~(7,116~~	)	)	(127,~~840~~116		)	~~(134,279~~		)
Income tax provision (benefit)	(69		)		—			6			—
Income tax expense (benefit)	—			(69		)		—
Loss from continuing operations	(3929,~~249,347~~622		)	(3,249,347	~~(7,116~~	)	)	(127,~~846~~116		)	~~(134,279~~		)
Loss from discontinued operations, net of tax	—			—	~~(7,746~~		)	(647,~~815~~746		)	~~(33,642~~		)
Net loss	(3929,~~249,347~~622		)	(3,249,347	$	~~(14,862~~)	)	$	(7714,~~661~~862	)	$	~~(167,921~~	)
Net loss attributable to non-controlling interest	(1479,~~724,648~~084		)	(1,724,648		)
Net Loss Attributable to Alta Mesa Resources, Inc. Stockholders	$	(1,524,699	)
Net loss attributable to Alta Mesa Resources, Inc. stockholders	$	(450,538	)	$	(1,524,699	)
Net Loss Per Common Share Attributable To Alta Mesa Resources, Inc. Stockholders:
Net loss per common share attributable to Alta Mesa Resources, Inc. stockholders:
Basic and diluted	$	(82.7148	)	$	(8.71	)

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

9040

Table of Contents

Index to Financial Statements

ALTA MESA RESOURCES, INC. (Debtor-in-possession)

CONSOLIDATED BALANCE SHEETS

(in thousands, except shares and per share data)

	Successor		Predecessor
	December 31, 2019		December 31, 2018
	December 31, 2018		December 31, 2017
ASSETS
Current assets
Cash and cash equivalents	$	2695,~~854~~367	$	326,~~660~~854
Restricted cash	~~1,001~~681		1,~~269~~001
Accounts receivable, net	8761,~~842~~187		7687,~~161~~842
Other receivables	61,~~331~~344		16,~~388~~331
Related party receivables	~~3,341~~—		~~790~~3,341
Prepaid expenses and other	18,~~125~~047		21,~~932~~125
Derivatives	~~16,423~~—		~~216~~16,423
Current assets — discontinued operations	—		5,195
Total current assets	166,626		142,917
Total current assets	142,917		91,611
Property and equipment
Property, plant and equipment
Oil and gas properties, successful efforts method, net	215,352		763,337
Oil and gas properties, successful efforts method, net	763,337		894,630
Other property and equipment, net	107,028		444,269
Other property, plant and equipment	444,269		32,140
Total property and equipment, net	322,380		1,207,606
Total property, plant and equipment, net	1,207,606		926,770
Other assets
Equity method investment	1,100		—
Operating lease right-of-use assets, net	—		—
Deferred financing costs	3,195		1,787
Equity method investment	—		1,100
Notes receivable from related party	—		12,369
Deferred financing costs, net	1,581		3,195
Intangible assets, net	—		—
Deposits and other long-term assets	7,993		65
Goodwill	—		—
Derivatives	—		2,947
Deposits and other long-term assets	65		9,067
Total other assets	9,574		7,307
Derivatives	2,947		8
Total assets	$	498,580	$	1,357,830
Noncurrent assets — discontinued operations	—		43,785
Total other assets	7,307		67,016
Total assets	$	1,357,830	$	1,085,397

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

9141

Table of Contents

Index to Financial Statements

	Successor			Predecessor
	December 31, 2019			December 31, 2018
	December 31, 2018			December 31, 2017
LIABILITIES AND STOCKHOLDERS’ EQUITY
LIABILITIES, PARTNERS’ CAPITAL AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of debt	$	~~690~~224,~~123~~000		$	—690,123
Accounts payable and accrued liabilities	~~247~~64,~~439~~137			~~170~~247,~~489~~439
Accounts payable to affiliate	—			5,476
Advances from non-operators	811			5,193
Advances from non-operators	5,193			5,502
Advances from related party	3,175			9,839
Advances from related party	9,839			23,390
Asset retirement obligations, current portion	34			2,079
Asset retirement obligations, current potion	2,079			69
Operating lease liability, current portion	88			—
Derivatives	~~1,710~~—			191,~~303~~710
Current liabilities — discontinued operations	—			15,419
Total current liabilities not subject to compromise	292,245			956,383
Total current liabilities	956,383			239,648
Long-term liabilities
Asset retirement obligations, net of current portion	913,~~473~~149			109,~~400~~473
Long-term debt	174,000			607,440
Long-term debt, net	—			174,000
Derivatives	180			1,114
Operating lease liabilities, net of current portion	189			—
Other long-term liabilities	1,667			5,488
Derivatives	—			180
Noncurrent liabilities — discontinued operations	—			66,862
Other long-term liabilities	3,360			1,667
Total long-term liabilities	185,320			691,304
Total long-term liabilities not subject to compromise	16,698			185,320
Total liabilities	1,141,703			930,952
Liabilities subject to compromise	896,862			—
Commitments and contingencies (Note 18)
Total liabilities	1,205,805			1,141,703
Commitments and contingencies (Note 19)
Preferred stock, $0.0001 par value
Class A: 1,000,000 shares authorized; 3 shares issued; 2 outstanding	—			—
Class B: 1,000,000 shares authorized; 1 share issued and outstanding	—			—
Partners’ capital	—			154,445
Stockholders’ equity
Common stock, $0.0001 par value
Class A: 1,200,000,000 shares authorized; 180,072,227 shares issued and outstanding	18			—
Class A: 1,200,000,000 shares authorized; 182,774,952 and 180,072,227 issued and outstanding at December 31, 2019 and December 31, 2018, respectively.	18			18
Class C: 280,000,000 shares authorized; 202,169,576 shares issued and outstanding	20			—
Class C: 280,000,000 shares authorized; 199,987,976 and 202,169,576 issued and outstanding at December 31, 2019 and December 31, 2018, respectively.	20			20
Additional paid in capital	1,~~503~~512,~~382~~716			—1,503,382
Accumulated deficit	(1,~~532~~983,~~813~~351		)	—(1,532,813		)
Total stockholders’ equity/partners’ capital	(29,393		)	154,445
Total stockholders’ equity	(470,597		)	(29,393		)
Noncontrolling interest	~~245~~(236,~~520~~628		)	—245,520
Total equity	~~216~~(707,~~127~~225		)	~~154~~216,~~445~~127
Total liabilities, partners’ capital and stockholders’ equity	$	1,357,830		$	1,085,397
Total liabilities and stockholders’ equity	$	498,580		$	1,357,830

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

9242

Table of Contents

Index to Financial Statements

ALTA MESA RESOURCES, INC. (Debtor-in-possession)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Successor				~~Predecessor~~			Predecessor
	February 9, 2018ThroughDecember 31, 2018				January 1, 2018ThroughFebruary 8, 2018			Year EndedDecember 31, 2017			Year EndedDecember 31, 2016
	Year Ended December 31, 2019			February 9, 2018ThroughDecember 31, 2018				January 1, 2018ThroughFebruary 8, 2018
Cash flows from operating activities:
Net loss	$	(3929,~~249,347~~622	)	$	$(3,249,347	~~(14,862~~)	)	$	(7714,~~661~~862	)	$	~~(167,921~~	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion and amortization	~~160~~132,~~942~~292			160,942	~~12,554~~			~~113~~12,~~634~~554			~~95,075~~
Provision for uncollectible related party receivables	22,438				—			—			—
Non-cash lease expense	3,122			—				—
Impairments	3,205,051				5,560			30,317			16,306
Provision for uncollectible receivables	3,528			22,438				—
Amortization of deferred financing costs	526				171			2,732			3,905
Impairment of assets	905,293			3,205,051				5,560
Amortization of debt (premium) discount	(4,512		)		—			—			468
Non-cash reorganization items, net	(26,160		)	—				—
Equity-based compensation expense	22,025				—			—			—
Amortization of deferred financing costs	658			526				171
Exploratory dry hole expense	1,954				—			2,500			419
Amortization of debt premium	(3,432		)	(4,512		)		—
Expired leases	24,101				4,575			9,125			11,158
Equity-based compensation expense	6,412			22,025				—
(Gain) loss on derivatives	10,247				(6,663		)	(8,287		)	40,460
Non-cash exploration expense	43,412			26,055				4,575
Cash settlements of derivatives	(38,961		)		(2,296		)	4,117			88,689
(Gain) loss on derivatives	11,744			10,247				(6,663		)
Premium paid on derivatives	—				—			(520		)	—
Cash settlements of derivatives	7,642			(38,961		)		(2,296		)
Loss on debt extinguishment	—				—			—			18,151
Premium paid on derivatives	(1,906		)	—				—
Interest converted into debt related to Founder notes	—			—	~~103~~			~~1,209~~103			~~1,209~~
Interest added to notes receivable from related party	~~(949~~—		)	(949	~~(85~~	)	)	(~~867~~85		)	~~(774~~		)
(Gain) loss on sale of property and equipment	388				1,923			22,179			(3,542		)
Loss on sale of property and equipment	106			388				1,923
Gain on acquisitions of oil and gas properties	—				—			(3,294		)	—
Equity in earnings of unconsolidated subsidiaries	(6,216		)	—				—
Impact on cash from changes in:
Accounts receivable	1826,~~011~~323			18,011	~~(21,184~~		)	(4321,~~530~~184		)	~~(10,500~~		)
Other receivables	(4,~~045~~988		)	(4,045	~~(662~~	)	)	~~6,519~~(662		)	~~10,465~~
Receivables from related party	(11,468		)		(117		)	218			45
Related party receivables and payables	145			(11,468		)		(117		)
Prepaid expenses and other non-current assets	11,149				(591		)	(6,203		)	(819		)
Prepaid expenses and other assets	(29,078		)	11,149				(591		)
Advances from related party	(376,~~668~~664		)	(37,668	~~24,116~~	)		~~(19~~24,~~138~~116		)	~~42,528~~
Settlement of asset retirement obligations	(~~1,610~~234		)	(1,610	~~(63~~	)	)	(~~6,409~~63		)	~~(2,125~~		)
Accounts payable to related party	—				—			(2,170		)	—
Accounts payable, accrued liabilities and other liabilities	4,216			(41,463		)		23,857
Accounts payable, accrued liabilities and other liabilities	(41,463		)		23,857			34,857			(11,493		)
Operating lease obligations	(2,771		)	—				—
Cash from operating activities	86143,~~809~~798			86,809	~~26,336~~			5926,~~328~~336			~~131,704~~
Cash flows from investing activities:
Capital expenditures	(~~762~~327,~~760~~567		)	(762,760	~~(36,695~~	)	)	(~~313~~36,~~961~~695		)	~~(214,061~~		)
Acquisitions, net of cash acquired	~~(823,778~~—		)	(823,778	~~(1,218~~	)	)	(551,~~605~~218		)	~~(11,527~~		)
Proceeds withdrawn from Trust Account	~~1,042,742~~—			1,042,742	—			—			—
Contribution to equity method investment and other	(17,063		)		—			(1,515		)	—
Proceeds from (Contribution to) equity method investment and other	7,238			(17,063		)		—
Proceeds from sale of assets	~~312~~—			312	—			~~25,205~~—			~~1,290~~
Cash from investing activities	(~~560~~320,~~547~~329		)	(560,547	~~(37,913~~	)	)	(~~345~~37,~~876~~913		)	~~(224,298~~		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	~~431~~254,~~500~~362			431,500	~~60,000~~			~~373~~60,~~065~~000			~~722,557~~
Repayments of long-term debt	(~~273~~9,~~565~~496		)	(273,565	~~(43,000~~	)	)	(~~296~~43,~~622~~000		)	~~(921,034~~		)
Deferred financing costs paid	(3,722		)		—			(398		)	(13,747		)
Payment of taxes withheld on equity-based compensation awards	(142		)	—				—
Purchase and retirement of Class A common shares	(14,750		)		—			—			—
Deferred financing costs paid	—			(3,722		)		—
Capital distributions	—				(68		)	—			—
Purchase and retirement of Class A common shares	—			(14,750		)		—
Capital contributions	—				—			207,875			303,462
Capital contributions (distributions)	—			—				(68		)
Proceeds from issuance of Class A shares	~~400,000~~—			400,000	—			—			—
Repayment of sponsor note	~~(2,000~~—		)	(2,000	—	)		—			—
Repayment of deferred underwriting compensation	~~(36,225~~—		)	(36,225	—	)		—			—
Redemption of Class A common shares	~~(33~~—		)	(33	—	)		—			—
Cash from financing activities	~~501~~244,~~205~~724			501,205	~~16,932~~			~~283~~16,~~920~~932			~~91,238~~
Net increase (decrease) In cash, cash equivalents and restricted cash	27,467				5,355			(2,628		)	(1,356

Filing Compare · Alta Mesa Resources, Inc. /DE