0000003570false--12-312023FYhttp://fasb.org/us-gaap/2023#Revenueshttp://fasb.org/us-gaap/2023#Revenueshttp://fasb.org/us-gaap/2023#Revenueshttp://fasb.org/us-gaap/2023#DerivativeAssetsCurrenthttp://fasb.org/us-gaap/2023#DerivativeAssetsCurrenthttp://fasb.org/us-gaap/2023#DerivativeAssetsNoncurrenthttp://fasb.org/us-gaap/2023#DerivativeAssetsNoncurrenthttp://fasb.org/us-gaap/2023#DerivativeLiabilitiesCurrenthttp://fasb.org/us-gaap/2023#DerivativeLiabilitiesCurrenthttp://fasb.org/us-gaap/2023#DerivativeLiabilitiesNoncurrenthttp://fasb.org/us-gaap/2023#DerivativeLiabilitiesNoncurrenthttp://fasb.org/us-gaap/2023#DerivativeAssetsCurrenthttp://fasb.org/us-gaap/2023#DerivativeAssetsCurrenthttp://fasb.org/us-gaap/2023#DerivativeAssetsNoncurrenthttp://fasb.org/us-gaap/2023#DerivativeAssetsNoncurrenthttp://fasb.org/us-gaap/2023#DerivativeLiabilitiesCurrenthttp://fasb.org/us-gaap/2023#DerivativeLiabilitiesCurrenthttp://fasb.org/us-gaap/2023#DerivativeLiabilitiesNoncurrenthttp://fasb.org/us-gaap/2023#DerivativeLiabilitiesNoncurrentP5DP30DSOFR or base rateSOFR or base rateSOFR or base rateSOFR or base rateSOFR or base ratehttp://fasb.org/us-gaap/2023#OperatingLeaseRightOfUseAssethttp://fasb.org/us-gaap/2023#OperatingLeaseRightOfUseAssethttp://fasb.org/us-gaap/2023#PropertyPlantAndEquipmentNethttp://fasb.org/us-gaap/2023#PropertyPlantAndEquipmentNethttp://fasb.org/us-gaap/2023#OperatingLeaseLiabilityCurrenthttp://fasb.org/us-gaap/2023#OperatingLeaseLiabilityCurrenthttp://fasb.org/us-gaap/2023#OtherLiabilitiesCurrenthttp://fasb.org/us-gaap/2023#OtherLiabilitiesCurrenthttp://fasb.org/us-gaap/2023#OperatingLeaseLiabilityNoncurrenthttp://fasb.org/us-gaap/2023#OperatingLeaseLiabilityNoncurrenthttp://fasb.org/us-gaap/2023#FinanceLeaseLiabilityNoncurrenthttp://fasb.org/us-gaap/2023#FinanceLeaseLiabilityNoncurrentP1Y00000035702023-01-012023-12-3100000035702023-06-30iso4217:USD00000035702024-02-16xbrli:shares0000003570lng:LiquefiedNaturalGasMember2023-01-012023-12-310000003570lng:LiquefiedNaturalGasMember2022-01-012022-12-310000003570lng:LiquefiedNaturalGasMember2021-01-012021-12-310000003570lng:RegasificationServiceMember2023-01-012023-12-310000003570lng:RegasificationServiceMember2022-01-012022-12-310000003570lng:RegasificationServiceMember2021-01-012021-12-310000003570us-gaap:ProductAndServiceOtherMember2023-01-012023-12-310000003570us-gaap:ProductAndServiceOtherMember2022-01-012022-12-310000003570us-gaap:ProductAndServiceOtherMember2021-01-012021-12-3100000035702022-01-012022-12-3100000035702021-01-012021-12-31iso4217:USDxbrli:shares00000035702023-12-3100000035702022-12-310000003570us-gaap:TreasuryStockCommonMember2023-12-310000003570us-gaap:TreasuryStockCommonMember2022-12-310000003570lng:CheniereEnergyPartnersLPMember2023-12-310000003570us-gaap:CommonStockMember2020-12-310000003570us-gaap:TreasuryStockCommonMember2020-12-310000003570us-gaap:AdditionalPaidInCapitalMember2020-12-310000003570us-gaap:RetainedEarningsMember2020-12-310000003570us-gaap:NoncontrollingInterestMember2020-12-3100000035702020-12-310000003570us-gaap:CommonStockMember2021-01-012021-12-310000003570us-gaap:TreasuryStockCommonMember2021-01-012021-12-310000003570us-gaap:AdditionalPaidInCapitalMember2021-01-012021-12-310000003570us-gaap:RetainedEarningsMember2021-01-012021-12-310000003570us-gaap:NoncontrollingInterestMember2021-01-012021-12-310000003570us-gaap:CommonStockMember2021-12-310000003570us-gaap:TreasuryStockCommonMember2021-12-310000003570us-gaap:AdditionalPaidInCapitalMember2021-12-310000003570us-gaap:RetainedEarningsMember2021-12-310000003570us-gaap:NoncontrollingInterestMember2021-12-3100000035702021-12-310000003570us-gaap:CommonStockMember2022-01-012022-12-310000003570us-gaap:TreasuryStockCommonMember2022-01-012022-12-310000003570us-gaap:AdditionalPaidInCapitalMember2022-01-012022-12-310000003570us-gaap:RetainedEarningsMember2022-01-012022-12-310000003570us-gaap:NoncontrollingInterestMember2022-01-012022-12-310000003570us-gaap:CommonStockMember2022-12-310000003570us-gaap:AdditionalPaidInCapitalMember2022-12-310000003570us-gaap:RetainedEarningsMember2022-12-310000003570us-gaap:NoncontrollingInterestMember2022-12-310000003570us-gaap:CommonStockMember2023-01-012023-12-310000003570us-gaap:TreasuryStockCommonMember2023-01-012023-12-310000003570us-gaap:AdditionalPaidInCapitalMember2023-01-012023-12-310000003570us-gaap:RetainedEarningsMember2023-01-012023-12-310000003570us-gaap:NoncontrollingInterestMember2023-01-012023-12-310000003570us-gaap:CommonStockMember2023-12-310000003570us-gaap:AdditionalPaidInCapitalMember2023-12-310000003570us-gaap:RetainedEarningsMember2023-12-310000003570us-gaap:NoncontrollingInterestMember2023-12-31lng:unit0000003570lng:SabinePassLNGTerminalMember2023-01-012023-12-31lng:trainslng:milliontonnesutr:Ylng:item0000003570lng:CreoleTrailPipelineMember2023-01-012023-12-31utr:mi0000003570lng:CheniereEnergyPartnersLPMember2023-01-012023-12-31xbrli:pure0000003570lng:CorpusChristiLNGTerminalMember2023-01-012023-12-310000003570lng:CorpusChristiStage3ProjectMember2023-01-012023-12-310000003570srt:MinimumMemberlng:CorpusChristiStage3ProjectMember2023-01-012023-12-310000003570lng:CorpusChristiPipelineMember2023-01-012023-12-310000003570srt:MinimumMemberus-gaap:CustomerConcentrationRiskMember2023-01-012023-12-310000003570lng:SPACustomersMemberus-gaap:CustomerConcentrationRiskMember2023-01-012023-12-31lng:customer0000003570lng:SPAAndIPMCustomersMembersrt:WeightedAverageMember2023-01-012023-12-310000003570lng:SabinePassLNGTerminalMember2023-12-310000003570lng:SabinePassLNGTerminalMembersrt:MaximumMember2023-12-310000003570lng:CorpusChristiPipelineMember2023-12-310000003570lng:CreoleTrailPipelineMember2023-12-310000003570lng:SPLProjectAndCCLProjectMember2023-12-310000003570lng:SPLProjectAndCCLProjectMember2022-12-310000003570lng:SabinePassLiquefactionAndCorpusChristiLiquefactionMember2023-12-310000003570lng:SabinePassLiquefactionAndCorpusChristiLiquefactionMember2022-12-310000003570lng:CheniereMarketingLLCMember2023-12-310000003570lng:CheniereMarketingLLCMember2022-12-310000003570lng:OtherMember2023-12-310000003570lng:OtherMember2022-12-310000003570lng:LiquefiedNaturalGasInTransitInventoryMember2023-12-310000003570lng:LiquefiedNaturalGasInTransitInventoryMember2022-12-310000003570lng:LiquefiedNaturalGasInventoryMember2023-12-310000003570lng:LiquefiedNaturalGasInventoryMember2022-12-310000003570lng:MaterialsInventoryMember2023-12-310000003570lng:MaterialsInventoryMember2022-12-310000003570lng:NaturalGasInventoryMember2023-12-310000003570lng:NaturalGasInventoryMember2022-12-310000003570lng:OtherInventoryMember2023-12-310000003570lng:OtherInventoryMember2022-12-310000003570lng:TerminalAndInterconnectingPipelineFacilitiesMember2023-12-310000003570lng:TerminalAndInterconnectingPipelineFacilitiesMember2022-12-310000003570us-gaap:LandAndLandImprovementsMember2023-12-310000003570us-gaap:LandAndLandImprovementsMember2022-12-310000003570us-gaap:ConstructionInProgressMember2023-12-310000003570us-gaap:ConstructionInProgressMember2022-12-310000003570lng:TerminalAndRelatedAssetsMember2023-12-310000003570lng:TerminalAndRelatedAssetsMember2022-12-310000003570us-gaap:OfficeEquipmentMember2023-12-310000003570us-gaap:OfficeEquipmentMember2022-12-310000003570us-gaap:FurnitureAndFixturesMember2023-12-310000003570us-gaap:FurnitureAndFixturesMember2022-12-310000003570us-gaap:SoftwareAndSoftwareDevelopmentCostsMember2023-12-310000003570us-gaap:SoftwareAndSoftwareDevelopmentCostsMember2022-12-310000003570us-gaap:LeaseholdImprovementsMember2023-12-310000003570us-gaap:LeaseholdImprovementsMember2022-12-310000003570us-gaap:OtherCapitalizedPropertyPlantAndEquipmentMember2023-12-310000003570us-gaap:OtherCapitalizedPropertyPlantAndEquipmentMember2022-12-310000003570lng:FixedAssetsMember2023-12-310000003570lng:FixedAssetsMember2022-12-310000003570us-gaap:AssetsHeldUnderCapitalLeasesMember2023-12-310000003570us-gaap:AssetsHeldUnderCapitalLeasesMember2022-12-310000003570srt:MinimumMemberlng:TerminalAndRelatedAssetsMember2023-12-310000003570srt:MaximumMemberlng:TerminalAndRelatedAssetsMember2023-12-310000003570lng:LNGStorageTanksMember2023-12-310000003570us-gaap:PipelinesMember2023-12-310000003570lng:MarineBerthElectricalFacilityAndRoadsMember2023-12-310000003570lng:WaterPipelinesMember2023-12-310000003570lng:RegasificationProcessingEquipmentRecondensersVaporizationAndVentsMember2023-12-310000003570lng:SendoutPumpsMember2023-12-310000003570srt:MinimumMemberlng:LiquefactionProcessingEquipmentMember2023-12-310000003570srt:MaximumMemberlng:LiquefactionProcessingEquipmentMember2023-12-310000003570srt:MinimumMemberus-gaap:OtherEnergyEquipmentMember2023-12-310000003570srt:MaximumMemberus-gaap:OtherEnergyEquipmentMember2023-12-310000003570us-gaap:FairValueInputsLevel1Memberus-gaap:PriceRiskDerivativeMember2023-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:FairValueInputsLevel2Member2023-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:FairValueInputsLevel3Member2023-12-310000003570us-gaap:PriceRiskDerivativeMember2023-12-310000003570us-gaap:FairValueInputsLevel1Memberus-gaap:PriceRiskDerivativeMember2022-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:FairValueInputsLevel2Member2022-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:FairValueInputsLevel3Member2022-12-310000003570us-gaap:PriceRiskDerivativeMember2022-12-310000003570us-gaap:FairValueInputsLevel1Memberlng:LNGTradingDerivativeMember2023-12-310000003570us-gaap:FairValueInputsLevel2Memberlng:LNGTradingDerivativeMember2023-12-310000003570lng:LNGTradingDerivativeMemberus-gaap:FairValueInputsLevel3Member2023-12-310000003570lng:LNGTradingDerivativeMember2023-12-310000003570us-gaap:FairValueInputsLevel1Memberlng:LNGTradingDerivativeMember2022-12-310000003570us-gaap:FairValueInputsLevel2Memberlng:LNGTradingDerivativeMember2022-12-310000003570lng:LNGTradingDerivativeMemberus-gaap:FairValueInputsLevel3Member2022-12-310000003570lng:LNGTradingDerivativeMember2022-12-310000003570us-gaap:FairValueInputsLevel1Memberus-gaap:ForeignExchangeContractMember2023-12-310000003570us-gaap:ForeignExchangeContractMemberus-gaap:FairValueInputsLevel2Member2023-12-310000003570us-gaap:ForeignExchangeContractMemberus-gaap:FairValueInputsLevel3Member2023-12-310000003570us-gaap:ForeignExchangeContractMember2023-12-310000003570us-gaap:FairValueInputsLevel1Memberus-gaap:ForeignExchangeContractMember2022-12-310000003570us-gaap:ForeignExchangeContractMemberus-gaap:FairValueInputsLevel2Member2022-12-310000003570us-gaap:ForeignExchangeContractMemberus-gaap:FairValueInputsLevel3Member2022-12-310000003570us-gaap:ForeignExchangeContractMember2022-12-310000003570lng:PhysicalLiquefactionSupplyDerivativesMemberus-gaap:FairValueInputsLevel3Member2023-12-310000003570srt:MinimumMemberus-gaap:MarketApproachValuationTechniqueMemberlng:PhysicalLiquefactionSupplyDerivativesMemberus-gaap:FairValueInputsLevel3Member2023-01-012023-12-310000003570srt:MaximumMemberus-gaap:MarketApproachValuationTechniqueMemberlng:PhysicalLiquefactionSupplyDerivativesMemberus-gaap:FairValueInputsLevel3Member2023-01-012023-12-310000003570us-gaap:MarketApproachValuationTechniqueMembersrt:WeightedAverageMemberlng:PhysicalLiquefactionSupplyDerivativesMemberus-gaap:FairValueInputsLevel3Member2023-01-012023-12-310000003570srt:MinimumMemberus-gaap:ValuationTechniqueOptionPricingModelMemberlng:PhysicalLiquefactionSupplyDerivativesMemberus-gaap:FairValueInputsLevel3Member2023-01-012023-12-310000003570srt:MaximumMemberus-gaap:ValuationTechniqueOptionPricingModelMemberlng:PhysicalLiquefactionSupplyDerivativesMemberus-gaap:FairValueInputsLevel3Member2023-01-012023-12-310000003570us-gaap:ValuationTechniqueOptionPricingModelMembersrt:WeightedAverageMemberlng:PhysicalLiquefactionSupplyDerivativesMemberus-gaap:FairValueInputsLevel3Member2023-01-012023-12-310000003570lng:PhysicalLiquefactionSupplyDerivativesAndPhysicalLNGTradingDerivativeMember2022-12-310000003570lng:PhysicalLiquefactionSupplyDerivativesAndPhysicalLNGTradingDerivativeMember2021-12-310000003570lng:PhysicalLiquefactionSupplyDerivativesAndPhysicalLNGTradingDerivativeMember2020-12-310000003570lng:PhysicalLiquefactionSupplyDerivativesAndPhysicalLNGTradingDerivativeMember2023-01-012023-12-310000003570lng:PhysicalLiquefactionSupplyDerivativesAndPhysicalLNGTradingDerivativeMember2022-01-012022-12-310000003570lng:PhysicalLiquefactionSupplyDerivativesAndPhysicalLNGTradingDerivativeMember2021-01-012021-12-310000003570lng:PhysicalLiquefactionSupplyDerivativesAndPhysicalLNGTradingDerivativeMember2023-12-310000003570srt:MaximumMemberlng:PhysicalLiquefactionSupplyDerivativesMember2023-01-012023-12-310000003570srt:MaximumMemberlng:LNGTradingDerivativeMember2023-01-012023-12-310000003570us-gaap:CommodityContractMember2023-01-012023-12-31lng:tbtu0000003570lng:LNGTradingDerivativeMemberus-gaap:SalesMember2023-01-012023-12-310000003570lng:LNGTradingDerivativeMemberus-gaap:SalesMember2022-01-012022-12-310000003570lng:LNGTradingDerivativeMemberus-gaap:SalesMember2021-01-012021-12-310000003570lng:LNGTradingDerivativeMemberus-gaap:CostOfSalesMember2023-01-012023-12-310000003570lng:LNGTradingDerivativeMemberus-gaap:CostOfSalesMember2022-01-012022-12-310000003570lng:LNGTradingDerivativeMemberus-gaap:CostOfSalesMember2021-01-012021-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:SalesMember2023-01-012023-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:SalesMember2022-01-012022-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:SalesMember2021-01-012021-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:CostOfSalesMember2023-01-012023-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:CostOfSalesMember2022-01-012022-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:CostOfSalesMember2021-01-012021-12-310000003570us-gaap:ForeignExchangeContractMembersrt:MaximumMember2023-01-012023-12-310000003570us-gaap:ForeignExchangeContractMember2023-01-012023-12-310000003570us-gaap:ForeignExchangeContractMember2022-01-012022-12-310000003570us-gaap:ForeignExchangeContractMember2021-01-012021-12-310000003570lng:PriceRiskDerivativeAssetMember2023-12-310000003570lng:LNGTradingDerivativeAssetMember2023-12-310000003570lng:ForeignExchangeContractAssetMember2023-12-310000003570lng:PriceRiskDerivativeLiabilityMember2023-12-310000003570lng:LNGTradingDerivativesLiabilityMember2023-12-310000003570lng:ForeignExchangeContractLiabilityMember2023-12-310000003570lng:PriceRiskDerivativeAssetMember2022-12-310000003570lng:LNGTradingDerivativeAssetMember2022-12-310000003570lng:ForeignExchangeContractAssetMember2022-12-310000003570lng:PriceRiskDerivativeLiabilityMember2022-12-310000003570lng:LNGTradingDerivativesLiabilityMember2022-12-310000003570lng:ForeignExchangeContractLiabilityMember2022-12-310000003570lng:CommonUnitsMemberlng:CheniereEnergyPartnersLPMember2023-12-310000003570lng:BlackstoneCqpHoldcoLpMemberlng:ClassBUnitsMemberlng:CheniereEnergyPartnersLPMember2012-01-012012-12-310000003570lng:BlackstoneCqpHoldcoLpMemberlng:CheniereEnergyPartnersGPLLCMember2023-01-012023-12-310000003570lng:CheniereEnergyIncMemberlng:CheniereEnergyPartnersGPLLCMember2023-01-012023-12-310000003570lng:BlackstoneCQPHoldcoLPAndCheniereEnergyIncMemberlng:CheniereEnergyPartnersGPLLCMember2023-01-012023-12-310000003570lng:BlackstoneCqpHoldcoLpMember2023-01-012023-12-310000003570lng:BlackstoneCqpHoldcoLpMemberlng:CheniereEnergyPartnersLPMemberlng:DirectorAppointmentEntitlementMinimumMember2023-01-012023-12-310000003570lng:CheniereEnergyPartnersLPMember2023-01-012023-12-310000003570lng:CheniereEnergyPartnersLPMember2022-12-310000003570lng:A2024SabinePassLiquefactionSeniorNotesMember2023-12-310000003570lng:A2024SabinePassLiquefactionSeniorNotesMember2022-12-310000003570lng:A2025SabinePassLiquefactionSeniorNotesMember2023-12-310000003570lng:A2025SabinePassLiquefactionSeniorNotesMember2022-12-310000003570lng:A2026SabinePassLiquefactionSeniorNotesMember2023-12-310000003570lng:A2026SabinePassLiquefactionSeniorNotesMember2022-12-310000003570lng:A2027SabinePassLiquefactionSeniorNotesMember2023-12-310000003570lng:A2027SabinePassLiquefactionSeniorNotesMember2022-12-310000003570lng:A2028SabinePassLiquefactionSeniorNotesMember2023-12-310000003570lng:A2028SabinePassLiquefactionSeniorNotesMember2022-12-310000003570lng:A2030SabinePassLiquefactionSeniorNotesMember2023-12-310000003570lng:A2030SabinePassLiquefactionSeniorNotesMember2022-12-310000003570lng:A2037SabinePassLiquefactionNotesMembersrt:WeightedAverageMember2023-12-310000003570lng:A2037SabinePassLiquefactionNotesMember2023-12-310000003570lng:A2037SabinePassLiquefactionNotesMember2022-12-310000003570lng:SabinePassLiquefactionSeniorNotesMember2023-12-310000003570lng:SabinePassLiquefactionSeniorNotesMember2022-12-310000003570lng:A2020SPLWorkingCapitalFacilityMember2023-12-310000003570lng:A2020SPLWorkingCapitalFacilityMember2022-12-310000003570lng:SPLRevolvingCreditFacilityMember2023-12-310000003570lng:SPLRevolvingCreditFacilityMember2022-12-310000003570lng:SabinePassLiquefactionMember2023-12-310000003570lng:SabinePassLiquefactionMember2022-12-310000003570lng:A2029CheniereEnergyPartnersSeniorNotesMember2023-12-310000003570lng:A2029CheniereEnergyPartnersSeniorNotesMember2022-12-310000003570lng:A2031CheniereEnergyPartnersSeniorNotesMember2023-12-310000003570lng:A2031CheniereEnergyPartnersSeniorNotesMember2022-12-310000003570lng:A2032CheniereEnergyPartnersSeniorNotesMember2023-12-310000003570lng:A2032CheniereEnergyPartnersSeniorNotesMember2022-12-310000003570lng:A2033CheniereEnergyPartnersSeniorNotesMember2023-12-310000003570lng:A2033CheniereEnergyPartnersSeniorNotesMember2022-12-310000003570lng:CheniereEnergyPartnersSeniorNotesMember2023-12-310000003570lng:CheniereEnergyPartnersSeniorNotesMember2022-12-310000003570lng:A2019CQPCreditFacilitiesMember2023-12-310000003570lng:A2019CQPCreditFacilitiesMember2022-12-310000003570lng:CQPRevolvingCreditFacilityMember2023-12-310000003570lng:CQPRevolvingCreditFacilityMember2022-12-310000003570lng:A2024CorpusChristiHoldingsSeniorNotesMember2023-12-310000003570lng:A2024CorpusChristiHoldingsSeniorNotesMember2022-12-310000003570lng:A2025CorpusChristiHoldingsSeniorNotesMember2023-12-310000003570lng:A2025CorpusChristiHoldingsSeniorNotesMember2022-12-310000003570lng:A2027CorpusChristiHoldingsSeniorNotesMember2023-12-310000003570lng:A2027CorpusChristiHoldingsSeniorNotesMember2022-12-310000003570lng:A2029CorpusChristiHoldingsSeniorNotesMember2023-12-310000003570lng:A2029CorpusChristiHoldingsSeniorNotesMember2022-12-310000003570srt:WeightedAverageMemberlng:A2039CorpusChristiHoldingsSeniorNotesMember2023-12-310000003570lng:A2039CorpusChristiHoldingsSeniorNotesMember2023-12-310000003570lng:A2039CorpusChristiHoldingsSeniorNotesMember2022-12-310000003570lng:CorpusChristiHoldingsSeniorNotesMember2023-12-310000003570lng:CorpusChristiHoldingsSeniorNotesMember2022-12-310000003570lng:A2015CCHTermLoanFacilityMember2023-12-310000003570lng:A2015CCHTermLoanFacilityMember2022-12-310000003570lng:CorpusChristiHoldingsWorkingCapitalFacilityMember2023-12-310000003570lng:CorpusChristiHoldingsWorkingCapitalFacilityMember2022-12-310000003570lng:CheniereCorpusChristiHoldingsLLCMember2023-12-310000003570lng:CheniereCorpusChristiHoldingsLLCMember2022-12-310000003570lng:A2028CheniereSeniorSecuredNotesMember2023-12-310000003570lng:A2028CheniereSeniorSecuredNotesMember2022-12-310000003570lng:CheniereRevolvingCreditFacilityMember2023-12-310000003570lng:CheniereRevolvingCreditFacilityMember2022-12-310000003570srt:ParentCompanyMember2023-12-310000003570srt:ParentCompanyMember2022-12-310000003570lng:CorpusChristiHoldingsWorkingCapitalFacilityMember2023-01-012023-12-310000003570lng:A2033CheniereEnergyPartnersSeniorNotesMemberlng:CheniereEnergyPartnersLPMember2023-01-012023-12-310000003570lng:SPLRevolvingCreditFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570srt:MinimumMemberlng:SPLRevolvingCreditFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570srt:MaximumMemberlng:SPLRevolvingCreditFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570srt:MinimumMemberus-gaap:BaseRateMemberlng:SPLRevolvingCreditFacilityMember2023-01-012023-12-310000003570us-gaap:BaseRateMembersrt:MaximumMemberlng:SPLRevolvingCreditFacilityMember2023-01-012023-12-310000003570lng:CQPRevolvingCreditFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570lng:CQPRevolvingCreditFacilityMembersrt:MinimumMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570lng:CQPRevolvingCreditFacilityMembersrt:MaximumMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570lng:CQPRevolvingCreditFacilityMembersrt:MinimumMemberus-gaap:BaseRateMember2023-01-012023-12-310000003570lng:CQPRevolvingCreditFacilityMemberus-gaap:BaseRateMembersrt:MaximumMember2023-01-012023-12-310000003570lng:A2015CCHTermLoanFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570us-gaap:BaseRateMemberlng:A2015CCHTermLoanFacilityMember2023-01-012023-12-310000003570lng:CorpusChristiHoldingsWorkingCapitalFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570srt:MinimumMemberlng:CorpusChristiHoldingsWorkingCapitalFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570srt:MaximumMemberlng:CorpusChristiHoldingsWorkingCapitalFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570srt:MinimumMemberus-gaap:BaseRateMemberlng:CorpusChristiHoldingsWorkingCapitalFacilityMember2023-01-012023-12-310000003570us-gaap:BaseRateMembersrt:MaximumMemberlng:CorpusChristiHoldingsWorkingCapitalFacilityMember2023-01-012023-12-310000003570lng:CheniereRevolvingCreditFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570srt:MinimumMemberlng:CheniereRevolvingCreditFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570srt:MaximumMemberlng:CheniereRevolvingCreditFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2023-01-012023-12-310000003570srt:MinimumMemberus-gaap:BaseRateMemberlng:CheniereRevolvingCreditFacilityMember2023-01-012023-12-310000003570us-gaap:BaseRateMembersrt:MaximumMemberlng:CheniereRevolvingCreditFacilityMember2023-01-012023-12-310000003570srt:MinimumMemberlng:SPLRevolvingCreditFacilityMember2023-01-012023-12-310000003570srt:MaximumMemberlng:SPLRevolvingCreditFacilityMember2023-01-012023-12-310000003570lng:CQPRevolvingCreditFacilityMembersrt:MinimumMember2023-01-012023-12-310000003570lng:CQPRevolvingCreditFacilityMembersrt:MaximumMember2023-01-012023-12-310000003570lng:A2015CCHTermLoanFacilityMember2023-01-012023-12-310000003570srt:MinimumMemberlng:CorpusChristiHoldingsWorkingCapitalFacilityMember2023-01-012023-12-310000003570srt:MaximumMemberlng:CorpusChristiHoldingsWorkingCapitalFacilityMember2023-01-012023-12-310000003570srt:MinimumMemberlng:CheniereRevolvingCreditFacilityMember2023-01-012023-12-310000003570srt:MaximumMemberlng:CheniereRevolvingCreditFacilityMember2023-01-012023-12-310000003570lng:SPLRevolvingCreditFacilityMember2023-01-012023-12-310000003570lng:CQPRevolvingCreditFacilityMember2023-01-012023-12-310000003570lng:CheniereRevolvingCreditFacilityMember2023-01-012023-12-310000003570srt:MaximumMemberlng:A2015CCHTermLoanFacilityMember2023-01-012023-12-310000003570lng:GainLossOnExtinguishmentOfObligationsMemberlng:ChevronUSAIncMember2022-01-012022-12-310000003570us-gaap:ConvertibleDebtMember2023-01-012023-12-310000003570us-gaap:ConvertibleDebtMember2022-01-012022-12-310000003570us-gaap:ConvertibleDebtMember2021-01-012021-12-310000003570lng:DebtExcludingCapitalLeaseAndConvertibleDebtMember2023-01-012023-12-310000003570lng:DebtExcludingCapitalLeaseAndConvertibleDebtMember2022-01-012022-12-310000003570lng:DebtExcludingCapitalLeaseAndConvertibleDebtMember2021-01-012021-12-310000003570us-gaap:SeniorNotesMemberus-gaap:CarryingReportedAmountFairValueDisclosureMemberlng:FairValueInputsLevel2AndLevel3Member2023-12-310000003570us-gaap:SeniorNotesMemberlng:FairValueInputsLevel2AndLevel3Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2023-12-310000003570us-gaap:SeniorNotesMemberus-gaap:CarryingReportedAmountFairValueDisclosureMemberlng:FairValueInputsLevel2AndLevel3Member2022-12-310000003570us-gaap:SeniorNotesMemberlng:FairValueInputsLevel2AndLevel3Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2022-12-310000003570us-gaap:SeniorNotesMemberus-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:FairValueInputsLevel3Member2022-12-310000003570us-gaap:SeniorNotesMemberus-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:FairValueInputsLevel3Member2023-12-310000003570us-gaap:OperatingExpenseMember2023-01-012023-12-310000003570us-gaap:OperatingExpenseMember2022-01-012022-12-310000003570us-gaap:OperatingExpenseMember2021-01-012021-12-310000003570lng:DepreciationandAmortizationExpenseMember2023-01-012023-12-310000003570lng:DepreciationandAmortizationExpenseMember2022-01-012022-12-310000003570lng:DepreciationandAmortizationExpenseMember2021-01-012021-12-310000003570us-gaap:InterestExpenseMember2023-01-012023-12-310000003570us-gaap:InterestExpenseMember2022-01-012022-12-310000003570us-gaap:InterestExpenseMember2021-01-012021-12-310000003570srt:MaximumMember2023-12-310000003570lng:LiquefiedNaturalGasProcuredFromThirdPartiesMember2023-01-012023-12-310000003570lng:LiquefiedNaturalGasProcuredFromThirdPartiesMember2022-01-012022-12-310000003570lng:LiquefiedNaturalGasProcuredFromThirdPartiesMember2021-01-012021-12-310000003570lng:TotalEnergiesGasPowerNorthAmericaIncMember2023-01-012023-12-310000003570lng:ChevronUSAIncMember2023-01-012023-12-310000003570lng:SabinePassLiquefactionMember2023-01-012023-12-310000003570lng:TerminalUseAgreementRegasificationCapacityPartialMember2023-01-012023-12-310000003570lng:TerminalUseAgreementRegasificationCapacityPartialMember2022-01-012022-12-310000003570lng:TerminalUseAgreementRegasificationCapacityPartialMember2021-01-012021-12-310000003570lng:ChevronUSAIncMember2022-06-012022-06-300000003570lng:RegasificationServiceMemberlng:ChevronUSAIncMember2023-01-012023-12-310000003570lng:ChevronUSAIncMemberlng:TerminatedCommitmentsMember2022-07-062022-12-3100000035702024-01-01lng:LiquefiedNaturalGasMember2023-12-3100000035702023-01-01lng:LiquefiedNaturalGasMember2022-12-310000003570lng:RegasificationServiceMember2024-01-012023-12-310000003570lng:RegasificationServiceMember2023-01-012022-12-3100000035702024-01-012023-12-3100000035702023-01-012022-12-310000003570lng:RelatedPartyThroughBrookfieldOwnershipMemberlng:NaturalGasTransportationAndStorageAgreementsMemberlng:LiquefiedNaturalGasMember2023-01-012023-12-310000003570lng:RelatedPartyThroughBrookfieldOwnershipMemberlng:NaturalGasTransportationAndStorageAgreementsMemberlng:LiquefiedNaturalGasMember2022-01-012022-12-310000003570lng:RelatedPartyThroughBrookfieldOwnershipMemberlng:NaturalGasTransportationAndStorageAgreementsMemberlng:LiquefiedNaturalGasMember2021-01-012021-12-310000003570lng:OperationAndMaintenanceAgreementMemberus-gaap:ProductAndServiceOtherMemberlng:MidshipPipelineMember2023-01-012023-12-310000003570lng:OperationAndMaintenanceAgreementMemberus-gaap:ProductAndServiceOtherMemberlng:MidshipPipelineMember2022-01-012022-12-310000003570lng:OperationAndMaintenanceAgreementMemberus-gaap:ProductAndServiceOtherMemberlng:MidshipPipelineMember2021-01-012021-12-310000003570lng:NaturalGasSupplyAgreementMember2023-01-012023-12-310000003570lng:NaturalGasSupplyAgreementMember2022-01-012022-12-310000003570lng:NaturalGasSupplyAgreementMember2021-01-012021-12-310000003570lng:NaturalGasTransportationAndStorageAgreementsMemberlng:RelatedPartyThroughBrookfieldOwnershipMember2023-01-012023-12-310000003570lng:NaturalGasTransportationAndStorageAgreementsMemberlng:RelatedPartyThroughBrookfieldOwnershipMember2022-01-012022-12-310000003570lng:NaturalGasTransportationAndStorageAgreementsMemberlng:RelatedPartyThroughBrookfieldOwnershipMember2021-01-012021-12-310000003570us-gaap:OtherAffiliatesMember2023-01-012023-12-310000003570us-gaap:OtherAffiliatesMember2022-01-012022-12-310000003570us-gaap:OtherAffiliatesMember2021-01-012021-12-310000003570lng:NaturalGasTransportationAndStorageAgreementsMemberlng:MidshipPipelineMember2023-01-012023-12-310000003570lng:NaturalGasTransportationAndStorageAgreementsMemberlng:MidshipPipelineMember2022-01-012022-12-310000003570lng:NaturalGasTransportationAndStorageAgreementsMemberlng:MidshipPipelineMember2021-01-012021-12-310000003570us-gaap:OtherAffiliatesMember2023-12-310000003570us-gaap:OtherAffiliatesMember2022-12-310000003570us-gaap:DomesticCountryMember2023-12-310000003570us-gaap:StateAndLocalJurisdictionMember2023-12-310000003570lng:A2011IncentivePlanMember2023-12-310000003570lng:A2020IncentivePlanMember2023-12-310000003570lng:EquityAwardsMember2023-01-012023-12-310000003570lng:EquityAwardsMember2022-01-012022-12-310000003570lng:EquityAwardsMember2021-01-012021-12-310000003570lng:LiabilityAwardsMember2023-01-012023-12-310000003570lng:LiabilityAwardsMember2022-01-012022-12-310000003570lng:LiabilityAwardsMember2021-01-012021-12-310000003570lng:RestrictedShareUnitAndPerformanceStockUnitAwardsMember2023-12-310000003570lng:RestrictedShareUnitAndPerformanceStockUnitAwardsMember2023-01-012023-12-310000003570us-gaap:RestrictedStockMember2023-01-012023-12-310000003570us-gaap:RestrictedStockMember2023-12-310000003570srt:MaximumMemberus-gaap:RestrictedStockUnitsRSUMember2023-01-012023-12-310000003570lng:EquityClassifiedRestrictedStockUnitsMember2023-01-012023-12-310000003570lng:EquityClassifiedRestrictedStockUnitsMember2022-12-310000003570lng:EquityClassifiedRestrictedStockUnitsMember2023-12-310000003570us-gaap:PerformanceSharesMember2023-01-012023-12-310000003570srt:MinimumMemberus-gaap:PerformanceSharesMember2023-01-012023-12-310000003570us-gaap:PerformanceSharesMembersrt:MaximumMember2023-01-012023-12-310000003570us-gaap:PerformanceSharesMember2022-01-012022-12-310000003570us-gaap:PerformanceSharesMember2021-01-012021-12-310000003570lng:EquityClassifiedPerformanceStockUnitsMember2023-01-012023-12-310000003570lng:EquityClassifiedPerformanceStockUnitsMember2022-12-310000003570lng:EquityClassifiedPerformanceStockUnitsMember2023-12-31lng:employees0000003570lng:LiabilityAwardsMember2023-12-310000003570lng:LiabilityAwardsMember2022-12-310000003570lng:LiabilityClassifiedRestrictedStockUnitsMember2023-12-310000003570lng:LiabilityClassifiedPerformanceStockUnitsMember2023-12-310000003570lng:LiabilityClassifiedRestrictedStockUnitsMember2022-12-310000003570lng:LiabilityClassifiedPerformanceStockUnitsMember2022-12-310000003570us-gaap:SubsequentEventMember2024-01-262024-01-260000003570lng:UnvestedStockMember2023-01-012023-12-310000003570lng:UnvestedStockMember2022-01-012022-12-310000003570lng:UnvestedStockMember2021-01-012021-12-310000003570lng:A2045ConvertibleSeniorNotesMember2023-12-310000003570lng:A2045ConvertibleSeniorNotesMember2023-01-012023-12-310000003570lng:A2045ConvertibleSeniorNotesMember2022-01-012022-12-310000003570lng:A2045ConvertibleSeniorNotesMember2021-01-012021-12-3100000035702021-09-3000000035702021-10-012021-10-010000003570lng:SubsequentBoardApprovedIncreaseMember2022-10-010000003570lng:SubsequentBoardApprovedIncreaseMember2022-10-012022-10-010000003570us-gaap:SubsequentEventMember2024-01-012024-02-160000003570lng:BechtelEPCContractCorpusChristiStage3Memberlng:CorpusChristiLiquefactionMember2023-01-012023-12-310000003570lng:BechtelEPCContractCorpusChristiStage3Memberlng:CorpusChristiLiquefactionMember2023-12-310000003570srt:MaximumMemberus-gaap:InventoriesMemberlng:SabinePassLiquefactionAndCorpusChristiLiquefactionMember2023-01-012023-12-310000003570srt:MaximumMemberus-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMemberlng:SabinePassLiquefactionAndCorpusChristiLiquefactionMember2023-01-012023-12-310000003570srt:MaximumMemberus-gaap:NaturalGasStorageMemberlng:SabinePassLiquefactionAndCorpusChristiLiquefactionMember2023-01-012023-12-310000003570lng:NaturalGasSupplyTransportationAndStorageServiceAgreementsMemberlng:SabinePassLiquefactionAndCorpusChristiLiquefactionMember2023-01-012023-12-310000003570lng:NaturalGasSupplyTransportationAndStorageServiceAgreementsMemberus-gaap:NonrelatedPartyMemberlng:SabinePassLiquefactionAndCorpusChristiLiquefactionMember2023-12-310000003570lng:NaturalGasSupplyTransportationAndStorageServiceAgreementsMemberus-gaap:OtherAffiliatesMemberlng:SabinePassLiquefactionAndCorpusChristiLiquefactionMember2023-12-310000003570lng:PartialTUAAssignmentAgreementAndOtherAgreementsMemberlng:SabinePassLiquefactionMember2023-01-012023-12-310000003570us-gaap:CustomerConcentrationRiskMemberus-gaap:SalesRevenueNetMemberlng:CustomerAMember2021-01-012021-12-310000003570lng:CustomerBMemberus-gaap:CustomerConcentrationRiskMemberus-gaap:SalesRevenueNetMember2021-01-012021-12-310000003570lng:CustomerCMemberus-gaap:CustomerConcentrationRiskMemberus-gaap:SalesRevenueNetMember2021-01-012021-12-310000003570lng:CustomerDMemberus-gaap:CustomerConcentrationRiskMemberlng:AccountsReceivableAndContractAssetsMember2023-01-012023-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:SG2023-01-012023-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:SG2022-01-012022-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:SG2021-01-012021-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:GB2023-01-012023-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:GB2022-01-012022-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:GB2021-01-012021-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:US2023-01-012023-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:US2022-01-012022-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:US2021-01-012021-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:IE2023-01-012023-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:IE2022-01-012022-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:IE2021-01-012021-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:KR2023-01-012023-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:KR2022-01-012022-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:KR2021-01-012021-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:ES2023-01-012023-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:ES2022-01-012022-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:ES2021-01-012021-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:IN2023-01-012023-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:IN2022-01-012022-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:IN2021-01-012021-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:CH2023-01-012023-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:CH2022-01-012022-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:CH2021-01-012021-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:DE2023-01-012023-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:DE2022-01-012022-12-310000003570us-gaap:GeographicConcentrationRiskMembercountry:DE2021-01-012021-12-310000003570us-gaap:GeographicConcentrationRiskMemberlng:OtherCountriesMember2023-01-012023-12-310000003570us-gaap:GeographicConcentrationRiskMemberlng:OtherCountriesMember2022-01-012022-12-310000003570us-gaap:GeographicConcentrationRiskMemberlng:OtherCountriesMember2021-01-012021-12-3100000035702023-10-012023-12-31

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2023
or
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to            
Commission file number 001-16383
colorlogoonwhitecmyka57.gif
CHENIERE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware95-4352386
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
845 Texas Avenue, Suite 1250
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713375-5000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: 
Title of each classTrading SymbolName of each exchange on which registered
Common Stock, $ 0.003 par valueLNGNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes    No 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes    No 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes    No 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes     No 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerAccelerated filer
Non-accelerated filerSmaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes    No   
The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $36.5 billion as of June 30, 2023.
As of February 16, 2024, the issuer had 234,692,274 shares of Common Stock outstanding.
Documents incorporated by reference: The definitive proxy statement for the registrant’s Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) is incorporated by reference into Part III.



CHENIERE ENERGY, INC.
TABLE OF CONTENTS

i

Table of Contents
DEFINITIONS

As used in this annual report, the terms listed below have the following meanings: 

Common Industry and Other Terms
ASUAccounting Standards Update
AFSIadjusted financial statement income
Bcfbillion cubic feet
Bcf/dbillion cubic feet per day
Bcf/yrbillion cubic feet per year
Bcfebillion cubic feet equivalent
CAMTcorporate alternative minimum tax
DATdelivered at terminal
DOEU.S. Department of Energy
EPCengineering, procurement and construction
ESGenvironmental, social and governance
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FIDfinal investment decision
FOBfree-on-board
FTA countriescountries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAPgenerally accepted accounting principles in the United States
Henry Hubthe final settlement price (in U.S. dollars per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
IPM agreementsintegrated production marketing agreements in which the gas producer sells to us gas on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs
LIBORLondon Interbank Offered Rate
LNGliquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtumillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
mtpamillion tonnes per annum
non-FTA countriescountries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SECU.S. Securities and Exchange Commission
SOFRSecured Overnight Financing Rate
SPALNG sale and purchase agreement
TBtu
trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
Trainan industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUAterminal use agreement

1

Table of Contents
Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2023, including our ownership of certain subsidiaries, and the references to these entities used in this annual report:

CEI  Org Chart - Q4 2023.jpg

Unless the context requires otherwise, references to “Cheniere,” the “Company,” “we,” “us” and “our” refer to Cheniere Energy, Inc. and its consolidated subsidiaries, including our publicly traded subsidiary, CQP.

2

Table of Contents

CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains certain statements that are, or may be deemed to be, “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 or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things: 
statements that we expect to commence or complete construction of our proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions or portions thereof, by certain dates, or at all;
statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;
statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
statements relating to Cheniere’s capital deployment, including intent, ability, extent and timing of capital expenditures, debt repayment, dividends, share repurchases and execution on the capital allocation plan;
statements regarding our future sources of liquidity and cash requirements;
statements relating to the construction of our Trains and pipelines, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;
statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject to contracts;
statements regarding counterparties to our commercial contracts, construction contracts and other contracts;
statements regarding our planned development and construction of additional Trains or pipelines, including the financing of such Trains or pipelines;
statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;
statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
statements regarding our anticipated LNG and natural gas marketing activities;
any other statements that relate to non-historical or future information; and
other factors described in Item 1A. Risk Factors in this Annual Report on Form 10-K.
All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the other reports and other information that we file with the SEC. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.
3

Table of Contents
PART I

ITEMS 1. AND 2.    BUSINESS AND PROPERTIES

General
 
Cheniere, a Delaware corporation, is a Houston-based energy infrastructure company primarily engaged in LNG-related businesses. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.

LNG is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, turned back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking, other industrial uses and back up for intermittent energy sources. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.

We are the largest producer of LNG in the United States and the second largest LNG operator globally, based on the total production capacity of our liquefaction facilities, which totals approximately 45 mtpa as of December 31, 2023.

We own and operate a natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, through our ownership interest in and management agreements with CQP, which is a publicly traded limited partnership that we formed in 2007. As of December 31, 2023, we owned 100% of the general partner interest, a 48.6% limited partner interest and 100% of the incentive distribution rights of CQP. The Sabine Pass LNG Terminal has six operational Trains, for a total production capacity of approximately 30 mtpa of LNG (the “SPL Project”). The Sabine Pass LNG Terminal also has operational regasification facilities that include five LNG storage tanks with aggregate capacity of approximately 17 Bcfe and vaporizers with regasification capacity of approximately 4 Bcf/d, as well as three marine berths, two of which can accommodate vessels with nominal capacity of up to 266,000 cubic meters and the third berth which can accommodate vessels with nominal capacity of up to 200,000 cubic meters. We also own and operate through CTPL, a subsidiary of CQP, a 94-mile natural gas supply pipeline that interconnects the Sabine Pass LNG Terminal with several interstate and intrastate pipelines (the “Creole Trail Pipeline”).
Additionally, we own and operate a natural gas liquefaction and export facility located near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”) through CCL, which has natural gas liquefaction facilities consisting of three operational Trains for a total production capacity of approximately 15 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. We are constructing an expansion of the Corpus Christi LNG Terminal (the “Corpus Christi Stage 3 Project”) for seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG. We also own and operate through CCP a 21.5-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Trains, storage tanks, and marine berths at the Corpus Christi LNG Terminal and the Corpus Christi Stage 3 Project, the “CCL Project”).

Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted substantially all of our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under IPM agreements, in which the gas producer sells natural gas to us on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs. The SPAs also have a variable fee component, which is generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. Through our SPAs and IPM agreements, we have contracted approximately 95% of the total anticipated production from the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) through the mid-2030s with approximately 16 years of weighted average remaining life as of
4



December 31, 2023, excluding volumes from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. We also market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL through our integrated marketing function.
We remain focused on safety, operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Projects as a result of debottlenecking and other optimization projects. We believe these factors provide a foundation for additional growth in our portfolio of customer contracts in the future. We hold significant land positions at both the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal, which provide opportunity for further liquefaction capacity expansion. In March 2023, certain of our subsidiaries submitted an application with the FERC under the Natural Gas Act (the “NGA”) for an expansion adjacent to the CCL Project consisting of two midscale Trains with an expected total production capacity of approximately 3 mtpa of LNG (the “CCL Midscale Trains 8 & 9 Project”). Additionally, in May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the National Environmental Policy Act (“NEPA”) for an expansion adjacent to the SPL Project with a potential production capacity of up to approximately 20 mtpa of total LNG capacity, inclusive of estimated debottlenecking opportunities (the “SPL Expansion Project”). The development of the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive FID.

Our Business Strategy

Our primary business strategy is to be a full-service LNG provider to worldwide end-use customers. We accomplish this objective by owning, constructing and operating LNG and natural gas infrastructure facilities to meet our long-term customers’ energy demands and: 
safely, efficiently and reliably operating and maintaining our assets;
procuring natural gas and pipeline transport capacity to our facilities;
providing value to our customers through destination flexibility, options not to lift cargoes and diversity of price and geography;
continuing to secure long-term customer contracts to support our planned expansion, including the FID of potential expansion projects beyond the Corpus Christi Stage 3 Project;
completing our construction projects safely, on-time and on-budget;
maximizing the production of LNG to serve our customers and generating steady and stable revenues and operating cash flows;
maintaining a flexible capital structure to finance the acquisition, development, construction and operation of the energy assets needed to supply our customers;
executing our “all of the above” capital allocation strategy, focused on strengthening our balance sheet, funding financially disciplined growth and returning capital to our stockholders; and
strategically identifying actionable and economic environmental solutions.

Our Business
 
We shipped our first LNG cargo in February 2016 and as of February 16, 2024, approximately 3,280 cumulative LNG cargoes totaling over 225 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects. Our LNG has been shipped to 39 countries and regions around the world.

Below is a discussion of our operations. For further discussion of our contractual obligations and cash requirements related to these operations, refer to Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

5



Sabine Pass LNG Terminal

Liquefaction Facilities and Expansion Project

The Sabine Pass LNG Terminal, as described above under the caption General, is one of the largest LNG production facilities in the world with six Trains, five storage tanks and three marine berths. Additionally, in May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project.

The following summarizes the volumes of natural gas for which we have received approvals from the FERC to site, construct and operate the Trains at the SPL Project and the orders we have received from the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG Terminal through December 31, 2050:
FERC Approved VolumeDOE Approved Volume
(in Bcf/yr)(in mtpa)(in Bcf/yr)(in mtpa)
FTA countries1,661.94331,661.9433
Non-FTA countries1,661.94331,661.9433
Natural Gas Supply, Transportation and Storage

SPL has secured natural gas feedstock for the SPL Project through long-term natural gas supply agreements, including an IPM agreement. SPL Stage V has also entered into an IPM agreement to supply the SPL Expansion Project, subject to Cheniere making a positive FID on the first train of the SPL Expansion Project. Additionally, to ensure that SPL is able to transport natural gas feedstock to the SPL Project and manage inventory levels, it has entered into firm pipeline transportation and storage contracts with third parties and CTPL.

Regasification Facilities
 
The Sabine Pass LNG Terminal, as described above under the caption General, has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG storage capacity of approximately 17 Bcfe. SPLNG has a long-term, third party TUA for 1 Bcf/d with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”), under which TotalEnergies is required to pay fixed monthly fees, whether or not it uses the regasification capacity it has reserved. Prior to its cancellation effective December 31, 2022, SPLNG also had a TUA for 1 Bcf/d with Chevron U.S.A. Inc. (“Chevron”). Approximately 2 Bcf/d of the remaining capacity has been reserved under a TUA by SPL, which also has a partial TUA assignment agreement with TotalEnergies, as further described in Note 13—Revenues of our Notes to Consolidated Financial Statements.

Corpus Christi LNG Terminal

Liquefaction Facilities and Expansion Projects

The Corpus Christi LNG Terminal, as described above under the caption General, includes three Trains, three storage tanks, two marine berths and the construction of the Corpus Christi Stage 3 Project with seven midscale Trains. Additionally, in March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project.

The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2023:
Overall project completion percentage51.4%
Completion percentage of:
Engineering83.7%
Procurement72.2%
Subcontract work66.9%
Construction11.1%
Date of expected substantial completion2Q/3Q 2025 - 2H 2026

6



The following summarizes the volumes of natural gas for which we have received approvals from the FERC to site, construct and operate the Trains at the CCL Project and the orders we have received from the DOE authorizing the export of domestically produced LNG by vessel from the Corpus Christi LNG Terminal through December 31, 2050:
FERC Approved VolumeDOE Approved Volume
(in Bcf/yr)(in mtpa)(in Bcf/yr)(in mtpa)
Trains 1 through 3 of the CCL Project:
FTA countries875.1617875.1617
Non-FTA countries875.1617875.1617
Corpus Christi Stage 3 Project:
FTA countries582.1411.45582.1411.45
Non-FTA countries582.1411.45582.1411.45

Natural Gas Supply, Transportation and Storage

CCL has secured natural gas feedstock for the Corpus Christi LNG Terminal through long-term natural gas supply agreements, including IPM agreements. Additionally, to ensure that CCL is able to transport and manage the natural gas feedstock to the Corpus Christi LNG Terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation and storage capacity from third parties and CCP.

Marketing

We market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL to other customers through Cheniere Marketing, our integrated marketing function. We have, and continue to develop, a portfolio of long-, medium- and short-term SPAs to transport and deliver commercial LNG cargoes to locations worldwide.

Customers

The concentration of our customer credit risk in excess of 10% of total revenues was as follows:
Percentage of Total Revenues from External Customers
Year Ended December 31,
202320222021
BG Gulf Coast LNG, LLC and affiliates
**12%
Naturgy LNG GOM, Limited
**12%
Korea Gas Corporation
**10%
* Less than 10%

All of the above customers contribute to our LNG revenues through SPA contracts.

Additional information regarding our customer contracts can be found in Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 21—Customer Concentration of our Notes to Consolidated Financial Statements.

Governmental Regulation
 
Our LNG terminals and pipelines are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. These rigorous regulatory requirements increase the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.

Federal Energy Regulatory Commission

The design, construction, operation, maintenance and expansion of our liquefaction facilities, the import or export of LNG and the purchase and transportation of natural gas in interstate commerce through our pipelines (including our Creole
7



Trail Pipeline and Corpus Christi Pipeline) are highly regulated activities subject to the jurisdiction of the FERC pursuant to the NGA. Under the NGA, the FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale for resale of natural gas in interstate commerce, to natural gas companies engaged in such transportation or sale and to the construction, operation, maintenance and expansion of LNG terminals and interstate natural gas pipelines.

The FERC’s authority to regulate interstate natural gas pipelines and the services that they provide generally includes regulation of:
rates and charges, and terms and conditions for natural gas transportation, storage and related services;
the certification and construction of new facilities and modification of existing facilities;
the extension and abandonment of services and facilities;
the administration of accounting and financial reporting regulations, including the maintenance of accounts and records;
the acquisition and disposition of facilities;
the initiation and discontinuation of services; and
various other matters.

Under the NGA, our pipelines are not permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including our own marketing affiliates. Those rates, terms and conditions must be public, and on file with the FERC. In contrast to pipeline regulation, the FERC does not require LNG terminal owners to provide open-access services at cost-based or regulated rates. Although the provisions that codified the FERC’s policy in this area expired on January 1, 2015, we see no indication that the FERC intends to change its policy in this area. On February 18, 2022, the FERC updated its 1999 Policy Statement on certification of new interstate natural gas facilities and the framework for the FERC’s decision-making process, modifying the standards that the FERC uses to evaluate applications to include, among other things, reasonably foreseeable greenhouse gas (“GHG”) emissions that may be attributable to the project and the project’s impact on environmental justice communities. On March 24, 2022, the FERC rescinded the Policy Statement, re-issued it as a draft and it remains pending. At this time, we do not expect it to have a material adverse effect on our operations.
We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate granted by the FERC with the issuance of our Certificate of Public Convenience and Necessity to our marketing affiliates. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation.

In order to site, construct and operate our LNG terminals, we received and are required to maintain authorizations from the FERC under Section 3 of the NGA as well as other material governmental and regulatory approvals and permits. The Energy Policy Act of 2005 (the “EPAct”) amended Section 3 of the NGA to establish or clarify the FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, unless specifically provided otherwise in the EPAct amendments to the NGA. For example, nothing in the EPAct amendments to the NGA were intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals or those of a state acting under federal law.
In March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project. In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project.

The FERC’s Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate that engages in natural gas marketing functions. The general principles of the FERC Standards of Conduct are: (1) independent functioning, which requires transmission function employees to function independently of marketing function employees; (2) no-conduit rule, which prohibits passing transmission function information to marketing function employees; and (3) transparency, which imposes posting requirements to detect undue preference due to the improper disclosure of non-public transmission function information. We have established the required policies, procedures and training to comply with the FERC’s Standards of Conduct.
8



All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC’s jurisdiction under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.
Several other governmental and regulatory approvals and permits are required throughout the life of our LNG terminals and our pipelines. In addition, our FERC orders require us to comply with certain ongoing conditions, reporting obligations and maintain other regulatory agency approvals throughout the life of our facilities. For example, throughout the life of our LNG terminals and our pipelines, we are subject to regular reporting requirements to the FERC, the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations has not materially affected our construction or operations.

DOE Export Licenses

The DOE has authorized the export of domestically produced LNG by vessel from the Sabine Pass LNG Terminal, as discussed in Sabine Pass LNG TerminalLiquefaction Facilities, and the Corpus Christi LNG Terminal, as discussed in Corpus Christi LNG TerminalLiquefaction Facilities. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.

Under Section 3 of the NGA, applications for exports of natural gas to FTA countries, which allow for national treatment for trade in natural gas, are “deemed to be consistent with the public interest” and shall be granted by the DOE without “modification or delay.” FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. FTAs with Israel and Costa Rica do not require national treatment for trade in natural gas. Applications for export of LNG to non-FTA countries are considered by the DOE in a notice and comment proceeding whereby the public and other interveners are provided the opportunity to comment and may assert that such authorization would not be consistent with the public interest. In January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of LNG to non-FTA countries until the DOE can update the underlying analyses for authorizations. We do not believe such a pause will have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, or liquidity. The CCL Midscale Trains 8 & 9 Project is currently our only project pending non-FTA export approval with the DOE, although such approval is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application in March 2023. We would anticipate seeking non-FTA export authorization from the DOE on the SPL Expansion Project in the future, having entered the pre-filing review process with the FERC in May 2023. See Sabine Pass LNG Terminal and Corpus Christi LNG Terminal sections above for FERC and DOE approved volumes on our existing Liquefaction Projects.

Pipeline and Hazardous Materials Safety Administration

Our LNG terminals as well as the Creole Trail Pipeline and the Corpus Christi Pipeline are subject to regulation by PHMSA. PHMSA is authorized by the applicable pipeline safety laws to establish minimum safety standards for certain pipelines and LNG facilities. The regulatory standards PHMSA has established are applicable to the design, installation, testing, construction, operation, maintenance and management of natural gas and hazardous liquid pipeline facilities and LNG facilities that affect interstate or foreign commerce. PHMSA has also established training, worker qualification and reporting requirements.

PHMSA performs inspections of pipeline and LNG facilities and has authority to undertake enforcement actions, including issuance of civil penalties up to approximately $266,000 per day per violation, with a maximum administrative civil penalty of approximately $2.7 million for any related series of violations.

Other Governmental Permits, Approvals and Authorizations

Construction and operation of the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal require additional permits, orders, approvals and consultations to be issued by various federal and state agencies, including the DOT, U.S. Army
9



Corps of Engineers (“USACE”), U.S. Department of Commerce, National Marine Fisheries Service, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the U.S. Environmental Protection Agency (the “EPA”), U.S. Department of Homeland Security, the Louisiana Department of Environmental Quality (the “LDEQ”), the Texas Commission on Environmental Quality (“TCEQ”) and the Railroad Commission of Texas.

The USACE issues its permits under the authority of the Clean Water Act (“CWA”) (Section 404) and the Rivers and Harbors Act (Section 10). The EPA administers the Clean Air Act (“CAA”), and has delegated authority to the TCEQ and LDEQ to issue the Title V Operating Permit and the Prevention of Significant Deterioration Permit. These two permits are issued by the LDEQ for the Sabine Pass LNG Terminal and CTPL and by the TCEQ for the CCL Project.

Commodity Futures Trading Commission (“CFTC”)

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in those markets. The CFTC has enacted a number of regulations pursuant to the Dodd-Frank Act, including the speculative position limit rules. Given the enactment of the speculative position limit rules, as well as the impact of other rules and regulations under the Dodd-Frank Act, the impact of such rules and regulations on our business continues to be uncertain, but is not expected to be material.

As required by the Dodd-Frank Act, the CFTC and federal banking regulators also adopted rules requiring swap dealers (as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We qualify as a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.

Pursuant to the Dodd-Frank Act, the CFTC adopted additional anti-manipulation and anti-disruptive trading practices regulations that prohibit, among other things, manipulative, deceptive or fraudulent schemes or material misrepresentation in the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge.

United Kingdom / European Regulations

Our European trading activities, which are primarily established in and operated out of the United Kingdom (“U.K.”), are subject to a number of European Union (“EU”) and U.K. laws and regulations, including but not limited to:
the European Market Infrastructure Regulation, which was designed to increase the transparency and stability of the European Economic Area (“EEA”) derivatives markets;
the Regulation on Wholesale Energy Market Integrity and Transparency, which prohibits market manipulation and insider trading in EEA wholesale energy markets and imposes various transparency and other obligations on participants active in these markets;
the Markets in Financial Instruments Directive and Regulation (“MiFID II”), which sets forth a financial services framework across the EEA, including rules for firms engaging in investment services and activities in connection with certain financial instruments, including a range of commodity derivatives; and
the Market Abuse Regulation, which was implemented to create an enhanced market abuse framework, and which applies generally to all financial instruments listed or traded on EEA trading venues (“Traded Instruments”) as well as other over-the-counter financial instruments priced on, or impacting, the price or value of the Traded Instrument.
Following the U.K.'s departure from the EU (“Brexit”), the EU-wide rules that applied to the U.K. while it was a member of the EU (and during the transition period) have been replicated, subject to certain amendments, to create a parallel set of rules applicable only in the U.K. As a result, we are subject to two sets of substantively similar rules based on the same
10



underlying legislation: (i) one set of rules that apply in the EEA (i.e. not including the U.K.) (the “EEA Rules”); and (ii) one set of rules that apply only in the U.K. (the “U.K. Onshored Rules”).

To the extent our trading activities have a nexus with the EEA, we comply with the EEA Rules. However, as our trading activities are primarily operated out of the U.K., the main rules that impact and apply to us on a day-to-day basis are the U.K. Onshored Rules.

In particular, under the U.K. Onshored Rules, firms engaging in investment services and activities under U.K. MiFID II must be authorized unless an exemption applies. We meet the criteria for an exemption and therefore do not need to be authorized under U.K. MiFID II.
In addition to the U.K. Onshored Rules, we are also subject to a separate, U.K.-specific regime that is not based on prior EU/EEA legislation. This is primarily set out in the U.K.’s Financial Services and Markets Act 2000 (“FSMA”) and Financial Services and Markets Act 2000 (Regulated Activities) Order 2001 (“RAO”), which, among other things, governs the regulation of financial services and markets in the U.K., and contains a definitive list of the specified kinds of activities and products that are regulated. Under these U.K.-specific rules, a firm engaging in regulated activities must be authorized unless an exclusion applies. We qualify under applicable exclusions and therefore are not required to be authorized under the U.K. FSMA/RAO regime.

In December 2022, the EU enacted regulations, which among other things established a market correction mechanism against excessively high LNG prices and provided for the collection of information though new reporting obligations that would be utilized to provide for a new LNG pricing assessment/benchmark. The applicable regulations are set forth in Council Regulation (EU) 2022/2576-2581. The impact of such regulations on our business remains uncertain, but is not expected to be material.

Violation of the foregoing laws and regulations could result in investigations, possible fines and penalties, and in some scenarios, criminal offenses, as well as reputational damage.

Brexit and Equivalence

As referenced above, the U.K. ceased to be a member of the EU on January 31, 2020. On December 24, 2020, the EU and the U.K. reached an agreement in principle on the terms of certain agreements and declarations governing the ongoing relationship between the EU and the U.K., including the EU-U.K. Trade and Cooperation Agreement (the “TCA”). The TCA is limited in its scope; in particular the TCA does not make any meaningful provision for the financial services sector. Uncertainties remain relating to certain aspects of the U.K.’s future economic, trading and legal relationships with the EU and with other countries.

The Financial Services and Markets Act 2023 (“FSMA 2023”) came into U.K. law in June 2023. FSMA 2023 is the framework for the U.K.’s post-Brexit financial legislative and regulatory landscape. It is intended to provide the foundations for a significant overhaul and re-structuring of the U.K. financial services and markets regimes. The changes include the revocation of retained EU laws, the introduction of new powers and objectives for the regulators of such markets, as well as a number of measures relevant to financial market infrastructure operators and market participants. Changes will be implemented pursuant to subsidiary legislation or directly by regulators. However, at this time it is not possible to determine whether any such actions would have a material impact on our business.

Environmental Regulation
  
Our LNG terminals are subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution, as further described in the risk factor Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions in Risks Relating to Regulations within Item 1A. Risk Factors. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.
 
11



Clean Air Act
 
Our LNG terminals are subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. However, we do not believe any such requirements will have a material adverse effect on our operations, or the construction and operations of our liquefaction facilities.

On February 28, 2022, the EPA removed a stay of formaldehyde standards in the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) Subpart YYYY for stationary combustion turbines located at major sources of hazardous air pollutant (“HAP”) emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022 and demonstrate initial compliance with those requirements by September 5, 2022. We do not believe that the construction and operations of our liquefaction facilities will be materially and adversely affected by such regulatory actions.
We are supportive of regulations reducing GHG emissions over time. Since 2009, the EPA has promulgated and finalized multiple GHG emissions regulations related to reporting and reductions of GHG emissions from our facilities. On December 2, 2023, the EPA issued final rules to reduce methane and volatile organic compounds (“VOC”) emissions from new, existing and modified emission sources in the oil and gas sector. These regulations will require monitoring of methane and VOC emissions at our compressor stations. We do not believe such regulations will have a material adverse effect on our operations, financial condition or results of operations.

From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. On August 16, 2022, President Biden signed H.R. 5376(P.L. 117-169), the Inflation Reduction Act of 2022 (“IRA”) which includes a charge on methane emissions above a certain methane intensity threshold for facilities that report their GHG emissions under the EPA’s Greenhouse Gas Emissions Reporting Program Part 98 regulations. The charge starts at $900 per metric ton of methane in 2024, $1,200 per metric ton in 2025, and increasing to $1,500 per metric ton in 2026 and beyond. In January 2024, the EPA issued a proposed rule to impose and collect the methane emissions charge authorized under the IRA. We do not believe the methane charge will have a material adverse effect on our operations, financial condition or results of operations.

Coastal Zone Management Act (“CZMA”)
 
The siting and construction of our LNG terminals within the coastal zone is subject to the requirements of the CZMA. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources, and in Texas, by the General Land Office). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.

Clean Water Act
 
Our LNG terminals are subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained prior to discharging pollutants into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Louisiana, by the LDEQ, and in Texas, by the TCEQ). The CWA regulatory programs, including the Section 404 dredge and fill permitting program and Section 401 water quality certification program carried out by the states, are frequently the subject of shifting agency interpretations and legal challenges, which at times can result in permitting delays.

Resource Conservation and Recovery Act (“RCRA”)
 
The federal RCRA and comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. When such wastes are generated in connection with the operations of our facilities, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.

12



Protection of Species, Habitats and Wetlands

Various federal and state statutes, such as the Endangered Species Act, the Migratory Bird Treaty Act, the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources. If one of our LNG terminals or pipelines adversely affects a protected species or its habitat, we may be required to develop and follow a plan to avoid those impacts. In that case, siting, construction or operations may be delayed or restricted and cause us to incur increased costs.
It is not possible at this time to predict how future regulations or legislation may address protection of species, habitats and wetlands and impact our business. However, we do not believe such regulatory actions will have a material adverse effect on our operations, or the construction and operations of our liquefaction facilities.

Market Factors and Competition

Market Factors

Our ability to enter into additional long-term SPAs to underpin the development of additional Trains, sell LNG through Cheniere Marketing or develop new projects is subject to market factors. These factors include changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, the extent of energy security needs in the EU and elsewhere, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas and other overarching factors such as global economic growth and the pace of any transition from fossil-based systems of energy production and consumption to alternative energy sources. In addition, our ability to obtain additional funding to execute our business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and our ability to access capital markets.

We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Market participants around the globe have shown commitments to environmental goals consistent with many policy initiatives that we believe are constructive for LNG demand and infrastructure growth. Currently, significant amounts of money are being invested across Europe, Asia and Latin America in natural gas projects under construction, and more continues to be earmarked to planned projects globally. In Europe, there are various plans to install more than 85 mtpa of import capacity over the near-term to secure access to LNG and displace Russian gas imports. In India, there are more than 11,000 kilometers of gas pipelines under construction to expand the gas distribution network and increase access to natural gas. And in China, billions of U.S. dollars have already been invested and hundreds of billions of U.S. dollars are expected to be further invested all along the natural gas value chain to enable growth and decrease harmful emissions. Furthermore, some of the existing integrated liquefaction facilities outside of the U.S. have been experiencing issues related to reduced feed gas as a result of depleting upstream resources. Global supply contributions from these plants have been decreasing and LNG supply growth is expected to help support these shortages.

As a result of these dynamics, we expect natural gas and LNG to continue to play an important role in satisfying energy demand going forward. In its forecast published in the third quarter of 2023, Wood Mackenzie Limited (“WoodMac”) forecasted that global demand for LNG would increase by approximately 60%, from approximately 411 mtpa, or 19.7 Tcf, in 2022, to 657 mtpa, or 31.5 Tcf, in 2040 and to 709 mtpa or 34 Tcf in 2050. In its forecast published in the third quarter of 2023, WoodMac also forecasted LNG production from existing operational facilities and new facilities already under construction would be able to supply the market with approximately 544 mtpa in 2040, declining to 477 mtpa in 2050. This could result in a market need for construction of an additional approximately 113 mtpa of LNG production by 2040 and about 231 mtpa by 2050. As a cleaner burning fuel with lower emissions than coal or liquid fuels in power generation, we expect natural gas and LNG to play a central role in balancing grids, serving as back up for intermittent energy sources and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Projects, as well as our proposed expansions at Sabine Pass and Corpus Christi, are competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.

We have limited exposure to oil price movements as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements indexed to Henry Hub. These agreements contain fixed fees that are required to be paid even if the customers elect to cancel or suspend delivery of LNG cargoes.  Through our SPAs and IPM agreements, we have contracted approximately 95% of the total anticipated production from the Liquefaction Projects through the mid-2030s with approximately 16 years of weighted average remaining life as of December 31, 2023, excluding volumes
13



from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation.

Competition

Despite the long term nature of our SPAs, when SPL, CCL or our integrated marketing function need to replace or amend any existing SPA or enter into new SPAs, they will compete with each other and other natural gas liquefaction projects throughout the world on the basis of price per contracted volume of LNG at that time. Revenues associated with any incremental volumes, including those sold by our integrated marketing function, will also be subject to market-based price competition. Many of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to LNG markets than us.

Corporate Responsibility

As described in Market Factors and Competition, we expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Our vision is to provide clean, secure and affordable energy to the world. This vision underpins our focus on responding to the world’s shared energy challenges—expanding the global supply of clean, secure and affordable energy, improving air quality, reducing emissions and supporting the transition to a lower-carbon future. Our approach to corporate responsibility is guided by our Climate and Sustainability Principles: Transparency, Science, Supply Chain and Operational Excellence. In August 2023, we published The Power of Connection, our fourth Corporate Responsibility (“CR”) report, which details our approach and progress on ESG matters. Our CR report is available at www.cheniere.com/our-responsibility/reporting-center. Information on our website, including the CR report, is not incorporated by reference into this Annual Report on Form 10-K. For further discussion on social and governance matters, see Human Capital Resources.

Our climate strategy is to measure and mitigate emissions – to better position our LNG supplies to remain competitive in a lower carbon future, providing energy, economic and environmental security to our customers across the world. To maximize the environmental benefits of our LNG, we believe it is important to develop future climate goals and strategies based on an accurate and holistic assessment of the emissions profile of our LNG, accounting for all steps in the supply chain.

Consequently, we have collaborated with natural gas midstream companies, technology providers and leading academic institutions on life-cycle assessment (“LCA”) models, quantification, monitoring, reporting and verification (“QMRV”) of GHG emissions and other research and development projects. We also co-founded and sponsored the Energy Emissions Modeling and Data Lab (“EEMDL”), a multidisciplinary research and education initiative led by the University of Texas at Austin in collaboration with Colorado State University and the Colorado School of Mines. In addition, we commenced providing Cargo Emissions Tags (“CE Tags”) to our long-term customers in June 2022, and in October 2022 joined the Oil and Gas Methane Partnership (“OGMP”) 2.0, the United Nations Environment Programme’s (“UNEP”) flagship oil and gas methane emissions reporting and mitigation initiative.

Our total incremental expenditures related to climate initiatives, including capital expenditures, were not material to our Consolidated Financial Statements during the years ended December 31, 2023, 2022 and 2021. However, as governments consider and implement actions to reduce GHG emissions and the transition to a lower-carbon economy continues to evolve, as described in Market Factors and Competition, we expect the scope and extent of our future climate and sustainability initiatives to evolve accordingly. While we have not incurred material direct expenditures related to climate change, we are proactive in our management of climate risks and opportunities, including compliance with existing and future government regulations. We face certain business and operational risks associated with physical impacts from climate change, such as exposure to severe weather events or changes in weather patterns, in addition to transition risks. Please see Item 1A. Risk Factors for additional discussion.

Subsidiaries
 
Substantially all of our assets are held by our subsidiaries. We conduct most of our business through these subsidiaries, including the development, construction and operation of our LNG terminal business and the development and operation of our LNG and natural gas marketing business.

14



Human Capital Resources

We are in a unique position as the first U.S. LNG company in the lower 48. As the first mover, we invest in the core human capital priorities — attracting, engaging and developing diverse talent and building an inclusive and equitable workplace — because they underpin our current and future success and ability to generate long-term value.
 
As of December 31, 2023, we had 1,605 full-time employees with 1,511 located in the U.S. and 94 located outside of the U.S. (primarily in the U.K.).
Our strength comes from the collective expertise of our diverse workforce and through our core values of teamwork, respect, accountability, integrity, nimble and safety (“TRAINS”). Our employees help drive our success, build our reputation, establish our legacy and deliver on our commitments to our customers. Through fulfilling career opportunities, training, development and a competitive compensation program, we aim to keep our employees engaged. Our voluntary turnover was 6.1% for 2023.
Our Chief Human Resources Officer oversees human capital management. This includes our approach to talent attraction and retention, rewards and remuneration, employee relations, employee engagement and training and development. Our Chief Compliance and Ethics Officer oversees the diversity, equity and inclusion (“DEI”) program. Both officers communicate progress on our programs to our board of directors (our “Board”) quarterly.  

Talent Attraction, Engagement and Retention

Our recruitment strategy is focused on attracting diverse and highly skilled talent. We offer competitive compensation and benefits, and work to develop and attract a strong talent pipeline through a range of internship, apprenticeship and vocational programs. We invest in opportunities to help local students and underserved communities gain specialized skills and create local jobs through sponsorship of apprenticeships and internships. On an annual basis, we participate in workforce availability studies in the geographic areas where we operate to ensure representation of the local workforce. Internally and externally, we post openings to attract individuals with a range of backgrounds, skills and experience, offering employee bonuses for referring highly qualified candidates.

We manage and measure organizational health with a view to gaining insight into employees’ experiences, levels of workplace satisfaction and feelings of engagement and inclusion with the company. Employees are encouraged to share ideas and concerns through multiple feedback channels including townhalls and hotlines which can be reached anonymously. Insights from these channels are used to develop both company-wide and business unit level talent development plans and training programs.

Compensation and Benefits

We provide robust compensation and benefits programs to our employees. In addition to salaries, all employees are eligible for annual bonuses and stock awards. Benefit plans, which vary by country, include a 401(k) plan, healthcare and insurance benefits, health savings and flexible spending accounts, paid time off, family leave, family care resources, employee assistance programs and tuition assistance. We link our annual incentive program to financial and non-financial performance metrics, including but not limited to, ESG and DEI performance criteria.

Diversity, Equity and Inclusion

We are committed to supporting a diverse and inclusive culture where all employees can thrive and feel welcomed and valued. To create this environment, we are committed to equal employment opportunity and to compliance with all federal, state and local laws that prohibit workplace discrimination, harassment and unlawful retaliation. Our Code of Business Conduct and Ethics, our TRAINS values and both our discrimination and harassment and equal employment opportunity policies demonstrate our commitment to building an inclusive workplace, regardless of race, beliefs, nationality, gender and sexual orientation or any other status protected by our policy. We are committed to providing fair and equitable employee programs including compensation and benefits. We provide executives and senior management with DEI training and Unconscious Bias training to all employees. In addition, we will continue our “Values in Action” efforts, which supports employees in identifying and implementing actions and behaviors that align with our TRAINS values.

15



Through our strategic recruitment efforts, we attract a variety of candidates with a diversity of backgrounds, skills, experience and expertise. Since 2019, we have had a 28.4% increase in racially or ethnically diverse employees and a 42% increase in racially or ethnically diverse management. In the past five years, the percentage of female employees remained steady at 26%. In 2023, we contributed over $1 million to DEI community efforts, of which approximately $250,000 was used to fund scholarship programs for students attending historically black colleges and universities in our communities. In addition, scholarship recipients are provided the opportunity to network with employees and apply for summer internships. We also committed to other scholarships and community efforts furthering our commitment to DEI.
We encourage our employees to leverage their unique backgrounds through involvement in various employee resource groups and employee networks. Groups such as WILS (Women Inspiring Leadership Success), EPN (Emerging Professional Network), Cultural Champions Teams and MVN (Military and Veterans Network), our newest employee resource group focused on military veterans help build a culture of inclusion.
Development and Training

As the first exporter of LNG in the lower 48 of the US, we faced the unique challenge of developing our own LNG talent. Our apprenticeship program prepares local students for careers in LNG. This program combines classroom education with training and on-site learning experiences at our facilities.

We strive to provide our people with all of the tools and support necessary for them to succeed. We actively encourage our employees to take ownership of their careers and offer a number of resources to do so. Employees receive mid-year and annual performance reviews, as well as frequent informal discussions to help meet their career goals. We also conduct annual talent reviews and succession planning sessions to ensure future organizational talent trends are met. To ensure safe, reliable and efficient operations in a highly regulated environment, we offer online and site-specific learning opportunities. We also provide employees, leaders and executives with targeted development programming to solidify internal talent pipelines and succession plans.

Employee Safety, Health and Wellness

The safety of our employees, contractors and communities is one of our core values, and is carried out through our required safety programs and safety and health related procedures. Safety efforts are led by our Executive Safety Committee, which includes the Chief Executive Officer, senior leaders from across the company and representatives from our sites. We focus our efforts on continuously improving our performance. For the year ended December 31, 2023, we had zero employee recordable injuries and five contractor recordable injuries. Our total recordable incident rate (employees and contractors combined) was 0.10, placing us in the top quartile of industry benchmarks based on Bureau of Labor safety statistics.

To support the well-being of our employees, we provide a wellness program that offers employees incentives to maintain an active lifestyle and set personal wellness goals. Incentives include online education related to health, nutrition, emotional health and vaccinations, as well as subsidies for fitness devices and gym memberships. We also offer mammography screenings, rooms for nursing mothers and biometric screenings on site.

Available Information

Our common stock has been publicly traded since March 24, 2003 and is traded on the New York Stock Exchange under the symbol “LNG.” Our principal executive offices are located at 845 Texas Avenue, Suite 1250, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K.

We will also make available to any stockholder, without charge, copies of our annual report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Cheniere Energy, Inc., Investor Relations Department, 845 Texas Avenue Suite 1250, Houston, Texas 77002 or call (713) 375-5000. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers.
16



Additionally, we encourage you to review our CR Report (located on our internet site at www.cheniere.com), for more detailed information regarding our Human Capital programs and initiatives, as well as our initiatives and metrics related to ESG. Nothing on our website, including our CR Report or sections thereof, shall be deemed incorporated by reference into this Annual Report.

ITEM 1A.    RISK FACTORS
 
The following are some of the important factors that should be considered when investing in us, as such risk factors could adversely affect our business, financial condition, results of operation or cash flows or have other adverse impacts, and could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
Risks Relating to Our Financial Matters;
Risks Relating to Our Operations and Industry; and
Risks Relating to Regulations.
Risks Relating to Our Financial Matters
 
An inability to source capital to supplement our available cash resources and existing credit facilities could cause us to have inadequate liquidity and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

As of December 31, 2023, we had, on a consolidated basis, $4.1 billion of cash and cash equivalents (of which $575 million was held by CQP), $459 million of restricted cash and cash equivalents (of which $56 million was held by CQP), a total of $7.6 billion of available commitments under our credit facilities and $23.9 billion of total debt outstanding (before unamortized discount and debt issuance costs). SPL, CQP, CCH and Cheniere operate with independent capital structures as further detailed in Note 11—Debt of our Notes to Consolidated Financial Statements. We incur, and will incur, significant interest expense relating to financing the assets at the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal, and we anticipate drawing on current committed facilities and/or incurring additional debt to finance the construction of the Corpus Christi Stage 3 Project, as well as the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project if a positive FID is made on these expansion projects. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, lending institutions’ evolving policies on financing businesses linked to fossil fuels and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.

Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant portion of our customers fails to perform its contractual obligations for any reason.

Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2023, we had SPAs with initial terms of 10 or more years with a total of 29 different third party customers.

While substantially all of our long-term third party customer arrangements are executed with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.
17



Additionally, our long-term SPAs entitle the customer to terminate their contractual obligations upon the occurrence of certain events which include, but are not limited to: (1) if we fail to make available specified scheduled cargo quantities; (2) delays in the commencement of commercial operations; and (3) under the majority of our SPAs, upon the occurrence of certain events of force majeure.
Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected.

Our subsidiaries may be restricted under the terms of their indebtedness from making distributions under certain circumstances, which may limit CQP’s ability to pay or increase distributions to us or inhibit our access to cash flows from the CCL Project and could materially and adversely affect us.

The agreements governing our subsidiaries’ indebtedness restrict payments that our subsidiaries can make to CQP or us in certain events. For example, SPL is restricted from making distributions under agreements governing its indebtedness generally unless, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a debt service coverage ratio of 1.25:1.00 is satisfied.
CCH is restricted from making distributions under agreements governing its indebtedness generally unless, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a debt service coverage ratio of 1.25:1.00 is satisfied. In addition, prior to completion of the Corpus Christi Stage 3 Project, CCH is also required to confirm that it has sufficient funds, including senior debt commitments, equity funding and projected contracted cash flows from the fixed price component of its third party SPAs, to meet remaining expenditures required for the Corpus Christi Stage 3 Project in order to achieve completion by a certain specified date.

Our subsidiaries’ inability to pay distributions to CQP or us as a result of the foregoing restrictions in the agreements governing their indebtedness may inhibit CQP’s ability to pay or increase distributions to us and its other unitholders or inhibit our access to cash flows from the CCL Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our efforts to manage commodity and financial risks through derivative instruments, including our IPM agreements, could adversely affect our earnings reported under GAAP and our liquidity.

We use derivative instruments to manage commodity, currency and financial market risks. The extent of our derivative position at any given time depends on our assessments of the markets for these commodities and related exposures. We currently account for our derivatives at fair value, with immediate recognition of changes in the fair value in earnings, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. Such valuations are primarily valued based on estimated forward commodity prices and are more susceptible to variability particularly when markets are volatile, which could have a significant adverse effect on our earnings reported under GAAP. For example, as described in Results of Operations in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, our net income for the year ended December 31, 2022 included $5.7 billion of losses resulting from changes in the fair values of our derivatives, of which substantially all of such losses were related to commodity derivative instruments indexed to international LNG prices, mainly our IPM agreements.

These transactions and other derivative transactions have and may continue to result in substantial volatility in results of operations reported under GAAP, particularly in periods of significant commodity, currency or financial market variability. For certain of these instruments, in the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments involves management’s judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

In addition, our liquidity may be adversely impacted by the cash margin requirements of the commodities exchanges or the failure of a counterparty to perform in accordance with a contract. As of December 31, 2023 and 2022, we had collateral posted with counterparties by us of $18 million and $134 million, respectively, which are included in margin deposits in our Consolidated Balance Sheets.

18



Restrictions in agreements governing us and our subsidiaries’ indebtedness may prevent us and our subsidiaries from engaging in certain beneficial transactions, which could materially and adversely affect us.

In addition to restrictions on the ability of us, CQP, SPL and CCH to make distributions or incur additional indebtedness, the agreements governing our indebtedness also contain various other covenants that may prevent us from engaging in beneficial transactions, including limitations on our ability to:
make certain investments;
purchase, redeem or retire equity interests;
issue preferred stock;
sell or transfer assets;
incur liens;
enter into transactions with affiliates;
consolidate, merge, sell or lease all or substantially all of our assets; and
enter into sale and leaseback transactions.

Any restrictions on the ability to engage in beneficial transactions could materially and adversely affect us.

Our ability to declare and pay dividends and repurchase shares is subject to certain considerations.

Dividends are authorized and determined by our Board in its sole discretion and depend upon a number of factors, including:
Cash available for distribution;
Our results of operations and anticipated future results of operations;
Our financial condition, especially in relation to the anticipated future capital needs of any expansion of our Liquefaction Facilities;
The level of distributions paid by comparable companies;
Our operating expenses; and
Other factors our Board deems relevant.

We expect to continue to pay quarterly dividends to our stockholders; however, our Board may reduce our dividend or cease declaring dividends at any time, including if it determines that our current or forecasted future cash flows provided by our operating activities, after deducting capital expenditures, investments and other commitments, are not sufficient to pay our desired levels of dividends to our stockholders or to pay dividends to our stockholders at all.
Additionally as of December 31, 2023, $2.1 billion of repurchase authority remained under our share repurchase program our Board had authorized. Our share repurchase program does not obligate us to acquire a specific number of shares during any period, and our decision to commence, discontinue or resume repurchases in any period will depend on the same factors that our Board may consider when declaring dividends, among others.

Any downward revision in the amount of dividends we pay to stockholders or the number of shares we purchase under our share repurchase program could have an adverse effect on the market price of our common stock.

19



Risks Relating to Our Operations and Industry
 
Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Projects, damage to our Liquefaction Projects and increased insurance costs, all of which could adversely affect us.

Weather events such as major hurricanes and winter storms have caused interruptions or temporary suspension in construction or operations at our facilities or caused minor damage to our facilities. Our risk of loss related to weather events or other disasters is limited by contractual provisions in our SPAs, which can provide under certain circumstances relief from operational events, and partially mitigated by insurance we maintain. Aggregate direct and indirect losses associated with the aforementioned weather events, net of insurance reimbursements, have not historically been material to our Consolidated Financial Statements, and we believe our insurance coverages maintained, existence of certain protective clauses within our SPAs and other risk management strategies mitigate our exposure to material losses. However, future adverse weather events and collateral effects, or other disasters such as explosions, fires, floods or severe droughts, could cause damage to, or interruption of operations at our terminals or related infrastructure, which could impact our operating results, increase insurance premiums or deductibles paid and delay or increase costs associated with the construction and development of the Liquefaction Projects or our other facilities. Our LNG terminal infrastructure and LNG facilities located in or near Corpus Christi, Texas and Sabine Pass, Louisiana are designed in accordance with requirements of 49 Code of Federal Regulations Part 193, Liquefied Natural Gas Facilities: Federal Safety Standards, and all applicable industry codes and standards.

Disruptions to the third party supply of natural gas to our pipelines and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We depend upon third party pipelines and other facilities that provide gas delivery options to our liquefaction facilities and pipelines. If any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to receive natural gas volumes to produce LNG or to continue shipping natural gas from producing regions or to end markets could be adversely impacted. Such disruptions to our third party supply of natural gas may also be caused by weather events or other disasters described in the risk factor Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Projects, damage to our Liquefaction Projects and increased insurance costs, all of which could adversely affect us. While certain contractual provisions in our SPAs can limit the potential impact of disruptions, and historical indirect losses incurred by us as a result of disruptions to our third party supply of natural gas have not been material, any significant disruption to our natural gas supply where we may not be protected could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.

Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. The supply of natural gas to our Liquefaction Projects to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of natural gas as a result of various factors, including non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the risk factor Disruptions to the third party supply of natural gas to our pipelines and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Our risk is in part mitigated by the diversification of our natural gas supply and transportation across suppliers and pipelines, and regionally across basins, and additionally, we have provisions within our supplier contracts that provide certain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events. While historically we have not incurred significant or prolonged disruptions to our natural gas supply that have resulted in a material adverse impact to our operations, due to the criticality of natural gas supply to our production of LNG, our failure to purchase or receive physical delivery of sufficient quantities of natural gas under circumstances where we may not be protected could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

20



Our ability to complete development and/or construction of additional Trains, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient funding, we may be unable to fully execute our business strategy.

We continuously pursue liquefaction expansion opportunities and other projects along the LNG value chain. As described further in Items 1. and 2. Business and Properties, we are currently developing the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project. The commercial development of an LNG facility takes a number of years and requires a substantial capital investment that is dependent on sufficient funding and commercial interest, among other factors.

We will require significant additional funding to be able to commence construction of the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project and any additional expansion projects, which we may not be able to obtain at a cost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in the development or construction of the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project or any additional expansion projects, and we may not be able to complete our business plan, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Cost overruns and delays in the completion of our expansion projects, including the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our investment decision on the Corpus Christi Stage 3 Project and any potential future expansion of LNG facilities, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, relies on cost estimates developed initially through front end engineering and design studies. However, due to the size and duration of construction of an LNG facility, the actual construction costs may be significantly higher than our current estimates as a result of many factors, including but not limited to changes in scope, the ability of Bechtel Energy Inc. (“Bechtel”) and our other contractors to execute successfully under their agreements, changes in commodity prices (particularly nickel and steel), escalating labor costs and the potential need for additional funds to be expended to maintain construction schedules or comply with existing or future environmental or other regulations. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both, including change orders to comply with existing or future environmental or other regulations. Additionally, our SPAs generally provide that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations. As a result, any significant construction delay, whatever the cause, could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Significant increases in the cost of a liquefaction project beyond the amounts that we estimate could impact the commercial viability of the project as well as require us to obtain additional sources of financing to fund our operations until the applicable liquefaction project is fully constructed (which could cause further delays), thereby negatively impacting our business and limiting our growth prospects. While historically we have not experienced cost overruns or construction delays that have had a significant adverse impact on our operations, factors giving rise to such events in the future may be outside of our control and could have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are subject to significant construction and operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.

The construction and operation of our LNG terminals and our pipelines are, and will be, subject to the inherent risks associated with these types of operations as discussed throughout our risk factors, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

21



We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. Although losses incurred as a result of self insured risk have not been material historically, the occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are dependent on our EPC partners and other contractors for the successful completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project.

Timely and cost-effective completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of our EPC partners, including Bechtel, and our other contractors under their agreements. The ability of our EPC partners and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:
design and engineer each Train to operate in accordance with specifications;
engage and retain third party subcontractors and procure equipment and supplies;
respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
attract, develop and retain skilled personnel, including engineers;
post required construction bonds and comply with the terms thereof;
manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
maintain their own financial condition, including adequate working capital.

Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the Corpus Christi Stage 3 Project and any potential expansion projects, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of EPC partners and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein.

Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the Corpus Christi Stage 3 Project and any potential expansion projects, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, or result in a contractor’s unwillingness to perform further work. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

There may be impediments to the transport of LNG, such as shortages of LNG vessels worldwide or operational impacts on LNG shipping, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We sell a significant amount of our LNG under delivered at terminal (“DAT”) terms requiring delivery to international destinations. To fulfill our transportation requirements under these arrangements, including those under long term SPAs, we depend on the ability to secure chartered vessels often through long term lease arrangements. The construction and delivery of LNG vessels require significant capital and long construction lead times, and we may execute charters several years before the lease arrangements commence.

22



Although we actively manage our vessel requirements in response to the market and our customer contracts, the availability of LNG vessels and transportation costs could be impacted to the detriment of our business and our customers because of:
an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
shortages of or delays in the receipt of necessary construction materials;
political or economic disturbances;
acts of war or piracy;
changes in governmental regulations or maritime self-regulatory organizations;
work stoppages or other labor disturbances;
bankruptcy or other financial crisis of shipbuilders or shipowners;
quality or engineering problems;
disruptions to maritime transportation routes, such as the recent security situation in the Gulf of Aden and congestion at the Panama Canal resulting from decreased water levels caused by prolonged drought conditions; and
weather interference or a catastrophic event, such as a major earthquake, tsunami or fire.

While our chartered vessels are operated by the ship owners and we are exposed to risks outside of our own control, we are generally protected through provisions in our charter agreements from transportation disruptions on the part of the ship owner, including disruptions due to off-hire and downtime periods or shipping delays. However, other events outside of our control where we may not be protected may have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Additionally, while our vessel charters allow us to secure fixed rates under long term contracts (in certain cases subject to inflation) and we generally structure our SPAs to recover any increase in such costs, our profitability, particularly relating to our short term or spot LNG sales outside of our SPAs, is largely dependent on the strength of international LNG markets. While historical downturns have not had a material adverse impact to our operations or results, any prolonged weakening of such markets could result in depressed or negative margins. See the risk factor Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects for additional discussion.

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
competitive liquefaction capacity in North America;
insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
insufficient LNG tanker capacity;
weather conditions, including temperature volatility resulting from climate change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand;
reduced demand and lower prices for natural gas;
increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;
23



cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;
changes in supplies of, and prices for, alternative energy sources which may reduce the demand for natural gas;
changes in regulatory, tax or other governmental policies regarding imported LNG, natural gas or alternative energy sources, which may reduce the demand for imported LNG and/or natural gas;
political conditions in customer regions;
sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;
adverse relative demand for LNG compared to other markets, which may decrease LNG imports from North America; and
cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect our LNG business and the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Failure of exported LNG to be a long term competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Operations of the Liquefaction Projects are dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from the United States and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.
Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction facilities in the United States.

As described in Market Factors and Competition, it is expected that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to alternative fossil fuel energy sources such as oil and coal. However, as a result of transitions globally from fossil-based systems of energy production and consumption to renewable energy sources, LNG may face increased competition from alternative, cleaner sources of energy as such alternative sources emerge. Additionally, LNG from the Liquefaction Projects also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Projects in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Projects, may also be impacted by an increase in natural gas prices in the United States.

As described in Market Factors and Competition, we have contracted through our SPAs and IPM agreements approximately 95% of the total anticipated production from the Liquefaction Projects through the mid-2030s, excluding volumes from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. However, as a result of the factors described above and other factors, the LNG we produce may not remain a long term competitive source of energy internationally, particularly when our existing long term contracts begin to expire. Any significant impediment to the ability to continue to secure long term commercial contracts or deliver LNG from the United States could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

24



We face competition based upon the international market price for LNG.
    
Our Liquefaction Projects are subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from our Liquefaction Projects are diverse and include, among others:
increases in worldwide LNG production capacity and availability of LNG for market supply;
increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
increases in the cost to supply natural gas feedstock to our Liquefaction Projects;
decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
increases in capacity and utilization of nuclear power and related facilities; and
displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.

A cyber attack involving our business, operational control systems or related infrastructure, or that of third party pipelines which supply the Liquefaction Facilities, could negatively impact our operations, result in data security breaches, impede the processing of transactions or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.

The pipeline and LNG industries are increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our trading, marketing, pipeline, liquefaction and shipping operations. Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyber attacks, including third party pipelines which supply natural gas to our Liquefaction Facilities. For example, in 2021 Colonial Pipeline suffered a ransomware attack that led to the complete shutdown of its pipeline system for six days. Should a multiple of the third party pipelines which supply our Liquefaction Facilities suffer similar concurrent attacks, the Liquefaction Facilities may not be able to obtain sufficient natural gas to operate at full capacity, or at all. A cyber attack involving our business or operational control systems or related infrastructure, or that of third party pipelines with which we do business, could negatively impact our operations, result in data security breaches, impede the processing of transactions, or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.

We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our senior management or other key personnel could affect our business results.

We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and pipelines and to provide our customers with the highest quality service. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers, remoteness of our site locations, general inflationary pressures, changes in applicable laws and regulations or labor disputes could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. In addition, we are also subject to increased competition for skilled workers from new entrants to the LNG market. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
25



We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term, other than our employment agreement with our President and Chief Executive Officer. The loss of the services of any of these individuals could have a material adverse effect on our business.

Outbreaks of infectious diseases, such as COVID-19, at one or more of our facilities could adversely affect our operations.

Our facilities at the Sabine Pass LNG Terminal and Corpus Christi LNG Terminal are critical infrastructure and continued to operate during the COVID-19 pandemic through our implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including subsequent variants, had no adverse impact on our on-going operations, the risk of future variants and other infectious diseases is unknown. While we believe we can continue to mitigate any significant adverse impact to our employees and operations at our critical facilities related to the virus in its current form, the outbreak of a more potent variant or another infectious disease in the future at one or more of our facilities could adversely affect our operations.

Risks Relating to Regulations

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, the development and operation of our pipelines and the export of LNG could impede operations and construction and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The design, construction and operation of interstate natural gas pipelines, LNG terminals, including the Liquefaction Projects, the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project and other facilities, as well as the import and export of LNG and the purchase and transportation of natural gas, are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG.

To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related facilities of the SPL Project, the three Trains and related facilities of the CCL Project and the seven midscale Trains and related facilities for the Corpus Christi Stage 3 Project, as well as orders under Section 7 of the NGA authorizing the construction and operation of the Creole Trail Pipeline and the Corpus Christi Pipeline. In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project and in March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project. To date, the DOE has also issued orders under Section 4 of the NGA authorizing SPL, CCL and the Corpus Christi Stage 3 Project to export domestically produced LNG. In January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of LNG to non-FTA countries until the DOE can update the underlying analyses for authorizations. We do not believe such a pause will have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, or liquidity. The CCL Midscale Trains 8 & 9 Project is currently our only project pending non-FTA export approval with the DOE, although such approval is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application in March 2023. We would anticipate seeking non-FTA export authorization from the DOE on the SPL Expansion Project in the future, having entered the pre-filing review process with the FERC in May 2023. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipelines on land owned by third parties. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.

Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. Failure to comply with or our inability to obtain and maintain existing or newly imposed approvals, permits and filings that may arise due to factors outside of our control such as a U.S. government disruption or shutdown, political opposition or local community resistance to our operations could impede the operation and construction of our infrastructure. In addition, certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis. Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
26



  Our interstate natural gas pipelines and their FERC gas tariffs are subject to FERC regulation. If we fail to comply with such regulation, we could be subject to substantial penalties and fines.

Our interstate natural gas pipelines are subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of 1978 (the “NGPA”). The FERC regulates the purchase and transportation of natural gas in interstate commerce, including the construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities. Under the NGA, the rates charged by our interstate natural gas pipelines must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any potential shipper with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our interstate pipelines could be subject to substantial penalties and fines.

In addition, as a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1.5 million per day for each violation.

Although the FERC has not imposed fines or penalties on us to date, we are exposed to substantial penalties and fines if we fail to comply with such regulations.

Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.
    
Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management, natural resources and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our LNG terminals, docks and pipelines, including FERC, PHMSA, EPA and the United States Coast Guard, to issue regulatory enforcement actions, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties, difficulty obtaining and maintaining permits from regulatory agencies or increased capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.
    
The EPA has finalized or proposed multiple GHG regulations that impact our assets and supply chain. On December 2, 2023, the EPA issued final rules to reduce methane and VOC emissions from new, existing and modified emission sources in the oil and gas sector. These regulations will require monitoring of methane and VOC emissions at our compressor stations. Further, the IRA includes a charge on methane emissions above certain emissions thresholds employing empirical emissions data that will apply to our facilities beginning in calendar year 2024. In January 2024, the EPA issued a proposed rule to impose and collect methane emissions charges authorized under the IRA. In addition, other international, federal and state initiatives may be considered in the future to address GHG emissions through treaty commitments, direct regulation, market-based regulations such as a GHG emissions tax or cap-and-trade programs or clean energy or performance-based standards. Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.

Revised, reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business.

27



On February 28, 2022, the EPA removed a stay of formaldehyde standards in the NESHAP Subpart YYYY for stationary combustion turbines located at major sources of HAP emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022 and demonstrate initial compliance with those requirements by September 5, 2022. We do not believe that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by such regulatory actions.
Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our terminals or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national or international climate change-related policies, could cause additional expenditures, restrictions and delays in our business and to our proposed construction activities, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances.

Total expenditures related to environmental and similar laws and governmental regulations, including capital expenditures, were immaterial to our Consolidated Financial Statements for the years ended December 31, 2023, 2022 and 2021. Revised, reinterpreted or additional laws and regulations that result in increased compliance, operating or construction costs or restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Pipeline safety and compliance programs and repairs may impose significant costs and liabilities on us.

The PHMSA requires pipeline operators to develop management programs to safely operate and maintain their pipelines and to comprehensively evaluate certain areas along their pipelines and take additional measures where necessary to protect pipeline segments located in “high or moderate consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
perform ongoing assessments of pipeline safety and compliance;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventative and mitigating actions.

We are required to utilize pipeline integrity management programs that are intended to maintain pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with applicable statutes and the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines, which for certain violations can aggregate up to as high as $2.7 million.
Additions or changes in tax laws and regulations could potentially affect our financial results or liquidity.

We are subject to various types of tax arising from normal business operations in the jurisdictions in which we operate and transact. Any changes to local, domestic or international tax laws and regulations, or their interpretation and application, including the Organization for Economic Cooperation and Development’s (the “OECD”) adopted model rules for a 15% global minimum tax (commonly referred to as Pillar Two), could affect our tax obligations, profitability and cash flows in the future. In addition, tax rates in the various jurisdictions in which we operate may change significantly due to political or economic factors beyond our control. We continuously monitor and assess proposed tax legislation that could negatively impact our business.

The IRA imposes a 15% CAMT effective in 2023, on an applicable corporation with average AFSI in excess of $1 billion for any three consecutive years preceding the current year. Cheniere expects to be an applicable corporation beginning in 2024. Based on the CAMT rules as currently enacted, the CAMT tax base would include any gains or losses arising from changes in fair value of our commodity derivatives that are recorded to our Consolidated Statements of Operations. Volatility in underlying commodity and financial markets could accelerate and cause volatility in our future cash tax payments, particularly in periods of significant commodity, currency or financial market variability. If the CAMT applies, we could be subject to an additional tax liability beyond the regular federal corporate tax liability, despite our federal net operating loss carryforwards, which could adversely impact our liquidity. Additionally, any implementing regulatory guidance related to the
28



CAMT issued by the U.S. Department of Treasury and the Internal Revenue Service in the future could potentially affect both the timing and amount of our CAMT cash tax payments.

Our ability to utilize our net operating loss carryforwards and certain other tax attributes may be limited.

As of December 31, 2023, our federal net operating loss (“NOL”) carryforwards were approximately $4.3 billion and not subject to expiration. We may experience an ownership change as a result of future changes in our stock ownership (some of which changes may not be within our control). If Cheniere undergoes an ownership change (generally defined as a greater than 50% cumulative change in the equity ownership of certain shareholders over a rolling three-year period) under Section 382 of the Internal Revenue Code, our ability to use our pre-ownership change NOL carryforwards to offset future taxable income may be limited. This, in turn, could materially delay our ability to use our NOLs to offset future taxable income and have an adverse effect on our future cash flows.

ITEM 1B.    UNRESOLVED STAFF COMMENTS
 
None.

ITEM 1C.    CYBERSECURITY
 
Cyberattacks represent a potentially significant risk to the Company and our industry. We have implemented policies and procedures that are intended to manage and reduce this risk.

Risk Management and Strategy

As part of our broader approach to risk management, our cybersecurity program is designed to follow an “identify, protect, detect, respond and recover” approach to cybersecurity that is based off of the National Institute of Standards and Technology Cybersecurity Framework (“CSF”). Our strategy also includes segmentation of corporate and operations networks, defense in depth and the least privileged access principle. Operational networks have fundamentally distinct safety and reliability standards and pose unique threats in comparison to information technology networks. Realizing these differences, we routinely evaluate opportunities to refine our cybersecurity program in order to mitigate operational network risks. We include business continuity planning as a component of our strategy to help ensure critical systems are available to support our company in the instance of a disruptive event. We also participate in various industry organizations to stay abreast of recent trends and developments.

On an ongoing basis, we assess our people, processes and technology and, when necessary, adjust the overall program in an effort to adapt to the ever-evolving cyber and geopolitical landscapes. We conduct regular assessments and audits, cross-functional risk mitigation exercises and risk strategy sessions to identify cybersecurity risks, applicable regulatory requirements and industry standards. These engagements are also designed to exercise, assess the maturity of and enhance our Cyber Incident Response Plan. To support these efforts, we have contracted with third parties to perform facility and system penetration tests, compromise assessments of information technology systems, and security maturity assessments of our corporate and operational networks. We maintain a training program to help our personnel identify and assist in mitigating cybersecurity and data security risks. Our employees and Board members participate in annual training, user awareness campaigns and additional issue-specific training as needed. We also provide annual training for certain contractors who have access to our information technology networks.

With respect to third party service providers, our information security program includes conducting risk-based due diligence of certain service providers’ information security programs prior to onboarding. We seek to contractually require third party service providers with access to our information technology systems, sensitive business data or personal information to maintain reasonable security controls and restrict their ability to use our data, including personal information, for purposes other than to provide services to us, except as required by applicable law. We also seek to negotiate contractual requirements which compel our service providers to notify us of information security incidents occurring on their systems which may affect our systems or data, including personal information.
During the year ended December 31, 2023, cybersecurity incidents and threats did not materially affect our business, results of operations or financial condition.

29



Governance

Our cybersecurity leadership team consists of our Director and Chief Information Security Officer (our “CISO”), Vice President and Chief Information Officer and Senior Vice President of Shared Services. These individuals collectively provide the strategic oversight of our cybersecurity governance, cyber risk management and security operations and are responsible for maintaining our technology defense posture and program. They have decades of experience managing strategic technology operations, including the identification of cybersecurity risk and the defense of information technology assets from global threats. Our CISO’s experience includes assessing risks, implementing governance programs, and responding to threats in oil and gas, electric and natural gas utilities and nuclear power generation companies. He maintains a Certified Information Security Manager certification from ISACA, secret clearance from the Department of Homeland Security and has played an active role in the development of various cybersecurity standards including the CSF.

Risks that could affect us are an integral part of our Board and Audit Committee deliberations throughout the year. Cybersecurity risks are integrated into our enterprise risk assessment process, which is reviewed by our Board at least annually. Our Board has oversight responsibility for assessing the primary risks facing us (including cybersecurity risks), the relative magnitude of these risks and management’s plan for mitigating these risks, while the Audit Committee has been delegated the authority to oversee and periodically review the security of our information technology systems and controls, including programs and defenses against cybersecurity threats. The Audit Committee discusses with management our cybersecurity risk exposures and the steps management has taken to mitigate such exposures, including our risk assessment and risk management policies. On a quarterly basis, our cybersecurity leadership team updates the Audit Committee on the overall status of our cybersecurity program, key operational metrics, current assessments, cybersecurity issues or events and pertinent events related to cybersecurity.

For additional information about cybersecurity risks, see the risk A cyber attack involving our business, operational control systems or related infrastructure, or that of third party pipelines which supply the Liquefaction Facilities, could negatively impact our operations, result in data security breaches, impede the processing of transactions or delay financial or compliance reporting under Risks Relating to Our Operations and Industry in Item 1A.Risk Factors.

ITEM 3. LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.

LDEQ Matter

Certain of our subsidiaries are in discussions with the LDEQ to resolve alleged non-compliance with national emission standards for formaldehyde from combustion turbines at the Sabine Pass LNG Terminal. The allegations are identified in a Consolidated Compliance Order and Notice of Potential Penalty, Tracking No. AE-CN-22-00833 (the “2023 Compliance Order”) issued by the LDEQ on April 12, 2023. In August 2004, the EPA stayed the application of the emission standard to combustion turbines such as those at the Sabine Pass LNG Terminal. In March 2022, the EPA lifted the stay, and in June 2022 our subsidiaries petitioned the EPA and LDEQ for approval of additional operating parameters to demonstrate compliance with the emission limitation. The petition remains pending. Our subsidiaries continue to work with the LDEQ to resolve the matters identified in the 2023 Compliance Order, including the petition pending with the EPA. As of December 2023, our subsidiaries have filed test results with the LDEQ indicating that for the initial compliance period all 44 turbines meet the relevant compliance standard. We do not expect that any ultimate penalty will have a material adverse impact on our financial results.

ITEM 4.    MINE SAFETY DISCLOSURE

Not applicable.
30



PART II

ITEM 5.    MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information, Holders and Dividend Policy

Our common stock has traded on the New York Stock Exchange under the symbol “LNG” since February 5, 2024, and previously traded on the NYSE American or its predecessors under the symbol “LNG” from March 24, 2003 through February 3, 2024. As of February 16, 2024, we had approximately 234.7 million shares of common stock outstanding held by 75 record owners.

We intend to continue to declare and pay quarterly dividends, with the goal of increasing the dividend over time. The declaration of dividends is subject to the discretion of our Board, and will depend on our financial condition and other factors deemed relevant by the Board. See the risk Our ability to declare and pay dividends and repurchase shares is subject to certain considerations under Risks Relating to Our Financial Matters in Item 1A. Risk Factors.

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchases for the three months ended December 31, 2023:
PeriodTotal Number of Shares PurchasedAverage Price Paid Per ShareTotal Number of Shares Purchased as a Part of Publicly Announced PlansApproximate Dollar Value of Shares That May Yet Be Purchased Under the Plans (in millions) (1)
October 1 - 31, 2023732,055$167.95732,055$2,357
November 1 - 30, 2023634,274$174.28634,274$2,247
December 1 - 31, 2023607,966$173.21607,966$2,141
Total1,974,295$171.601,974,295
(1)See Note 19—Share Repurchase Programs of our Notes to Consolidated Financial Statements for details on the amount authorized by our Board under our share repurchase programs.

31



Total Stockholder Return

The following is a customized peer group consisting of 17 companies (the “Peer Group”) that were selected because they are publicly traded companies that have comparable Global Industry Classification Standards. We also took into consideration those companies that have similar market capitalization, enterprise values and operating characteristics and capital intensity.
Peer Group
Air Products and Chemicals, Inc. (APD)
Marathon Petroleum Corporation (MPC)
Baker Hughes Company (BKR)
Occidental Petroleum Corporation (OXY)
ConocoPhillips (COP)
ONEOK, Inc. (OKE)
Enterprise Products Partners L.P. (EPD)
Phillips 66 (PSX)
EOG Resources, Inc. (EOG)Suncor Energy Inc. (SU)
Halliburton Company (HAL)Targa Resources Corp. (TRGP)
Hess Corporation (HES)Valero Energy Corporation (VLO)
Kinder Morgan, Inc. (KMI)
The Williams Companies, Inc. (WMB)
LyondellBasell Industries N.V. (LYB)

The following graph compares the five-year total return on our common stock, the S&P 500 Index and our Peer Group. The graph was constructed on the assumption that $100 was invested in our common stock, the S&P 500 Index and our Peer Group on December 31, 2018 and that any dividends were fully reinvested.
December 31,
Company / Index201820192020202120222023
Cheniere Energy, Inc.$100.00 $103.18 101.42 $171.88 $256.67 $295.20 
S&P 500 Index100.00 131.48 155.65 200.29 163.98 207.04 
Peer Group100.00 122.09 90.09 130.28 193.39 212.27 
2438
32




ITEM 6.    [Reserved]
ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Introduction
 
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Discussion of 2021 items and variance drivers between the year ended December 31, 2022 as compared to December 31, 2021 are not included herein and can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the fiscal year ended December 31, 2022.

Our discussion and analysis includes the following subjects: 
Overview
Overview of Significant Events
Market Environment
Results of Operations
Liquidity and Capital Resources
Summary of Critical Accounting Estimates
Recent Accounting Standards

Overview
 
We are an energy infrastructure company primarily engaged in LNG-related businesses. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We operate two natural gas liquefaction and export facilities at Sabine Pass, Louisiana and near Corpus Christi, Texas. For further discussion of our business, see Items 1. and 2. Business and Properties.

Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Through our SPAs and IPM agreements, we have contracted approximately 95% of the total anticipated production from the Liquefaction Projects through the mid-2030s with approximately 16 years of weighted average remaining life as of December 31, 2023, excluding volumes from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. The majority of our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. During 2023, we continued to grow our portfolio of SPA and IPM agreements, and we believe that continued global demand for natural gas and LNG, as further described in Market Factors and Competition in Items 1. and 2. Business and Properties, will provide a foundation for additional growth in our portfolio of customer contracts in the future. The continued strength and stability of our long-term cash flows served as the foundation of our revised comprehensive, long-term capital allocation plan announced in 2022, which includes an increased share repurchase authorization, decreased consolidated long-term leverage target, increased dividends and continued investment in accretive organic growth.

33

Table of Contents
Overview of Significant Events

Our significant events since January 1, 2023 and through the filing date of this Form 10-K include the following:

Strategic

In November 2023, we announced that SPL Stage V entered into an IPM agreement with ARC Resources U.S. Corp., a subsidiary of ARC Resources Ltd., to purchase 140,000 MMBtu per day of natural gas at a price based on the Dutch Title Transfer Facility (“TTF”), less a fixed regasification fee, fixed LNG shipping costs and a fixed liquefaction fee, for a term of approximately 15 years commencing with commercial operations of the first train of the SPL Expansion Project. This agreement is subject to CQP making a positive FID on the first train of the SPL Expansion Project or CQP unilaterally waiving that requirement.
Cheniere Marketing entered into long-term SPAs with Foran Energy Group Co. Ltd., BASF, ENN LNG (Singapore) Pte. Ltd., Equinor ASA and Korea Southern Power Co. Ltd. with estimated volumes totaling approximately 106 million tonnes of LNG and expected deliveries between 2026 and 2050. Approximately 65 million tonnes is subject to CQP making a positive FID on the first or second trains of the SPL Expansion Project, as applicable, or us unilaterally waiving that requirement. Each of these SPAs permit Cheniere Marketing to assign or novate the agreement to certain affiliates at a later date.
In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project, and in April 2023, one of our subsidiaries executed a contract with Bechtel to provide the front end engineering and design work on the project.
In April 2023, certain of our subsidiaries filed an application with the DOE with respect to the CCL Midscale Trains 8 & 9 Project, requesting authorization to export LNG to FTA countries and non-FTA countries. In July 2023, we received authorization from the DOE to export LNG to FTA countries.
In March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project.
On January 2, 2023, Corey Grindal, formerly Executive Vice President, Worldwide Trading, was promoted to Executive Vice President and Chief Operating Officer of the Company.

Operational

As of February 16, 2024, approximately 3,280 cumulative LNG cargoes totaling over 225 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.

Financial

We closed the following debt transactions:
In June 2023, CQP issued $1.4 billion aggregate principal amount of 5.950% Senior Notes due 2033 (the “2033 CQP Senior Notes”). Using contributed proceeds from the 2033 CQP Senior Notes together with cash on hand, SPL redeemed $1.4 billion of its 5.750% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”) in July 2023.
In June 2023, CQP entered into a $1.0 billion Senior Unsecured Revolving Credit and Guaranty Agreement (the “CQP Revolving Credit Facility”), and SPL entered into a $1.0 billion Senior Secured Revolving Credit and Guaranty Agreement (the “SPL Revolving Credit Facility”). The CQP Revolving Credit Facility and SPL Revolving Credit Facility each refinanced and replaced the respective existing credit facilities to, among other things, (1) extend the maturity date thereunder, (2) reduce the rate of interest and commitment fees applicable thereunder and (3) make certain other changes to the terms and conditions of the prior credit facilities.
34

Table of Contents
We received the following upgrades from credit rating agencies, including S&P Global Ratings (“S&P”), Moody’s Investor Service (“Moodys”) and Fitch Ratings (“Fitch”), each with a stable outlook:
DateEntityPrevious RatingUpgraded RatingRating Agency
October 2023CCHBBB-BBB
S&P
August 2023CheniereBa1Baa3
Moody’s
August 2023CCHBaa3Baa2
Moody’s
August 2023SPLBBBBBB+
Fitch
July 2023CCHBBB-BBB
Fitch
February 2023SPLBBBBBB+
S&P
January 2023CheniereBBB-
Fitch
During the year ended December 31, 2023, we accomplished the following pursuant to our capital allocation priorities:
We prepaid $1.2 billion of consolidated long-term indebtedness, which excludes prepayments associated with debt refinancing and includes $600 million of debt repurchases in the open market.
We repurchased approximately 9.5 million shares of our common stock as part of our share repurchase program for $1.5 billion.
We paid dividends of $1.620 per share of common stock during the year ended December 31, 2023.
We continued to invest in accretive organic growth, including our investment in the Corpus Christi Stage 3 Project, as further described under Investing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

Market Environment

In 2023, the LNG market continued to rebalance with robust LNG flows to Europe maintaining the region’s underground storage inventories at high levels, and weak demand in Japan and Korea largely offsetting a modest rebound in China and other emerging economies in Asia. Price levels started moving towards pre-Russia-Ukraine war levels in the second quarter of 2023 and have for the most part normalized versus pre-war levels, as concerns about physical market tightness dissipated. However, extensive upstream maintenance in Norway and concerns about tight supply capacity amid strike threats in Australia elevated prices during the third quarter of 2023 and brought some volatility back to the market, albeit not at much lower levels than those seen in 2022. These conditions were quickly resolved, and winter prices remained within a more normal level, despite the eruption of military conflict in the Middle East in October.

The TTF monthly settlement prices averaged $13.73/MMBtu in 2023, over 66% lower year-over-year and 4.6% lower than 2021. Similarly, the 2023 average settlement price for the Japan Korea Marker (“JKM”) decreased 53% year-over-year to an average of $16.13/MMBtu in 2023. Prices in the fourth quarter of 2023 also decreased, with TTF averaging $13.66/MMBtu and JKM $14.97/MMBtu - both significantly below levels seen in the previous two years. The Henry Hub benchmark also witnessed a similar year-over-year drop albeit from a much lower base. The Henry Hub average settlement price in 2023 was $2.74, down approximately 59% from $6.64/MMBtu in 2022 during the height of the energy crisis in Europe.

The U.S. played a significant role in balancing the global market in 2023, exporting approximately 86 million tonnes of LNG, a gain of approximately 13% from 2022, due in part to the return of Freeport LNG to operations. Exports from our Liquefaction Projects reached 44 million tonnes in aggregate, representing over 50% of total U.S. exports for the year, according to Kpler data.

Global LNG demand grew by approximately 3% from 2022, adding 10.5 million tonnes to the overall market. Although overall Asian demand has increased from 2022, weakness in Japan, mainly due to improved nuclear availability, along with continued gas demand destruction in Europe, especially in the residential sector, exerted downward pressure on the market and kept LNG and gas prices from increasing. Despite the decrease in Japanese demand, which was down approximately 8% or 6 mtpa year-over-year, Asia’s LNG imports increased roughly 4% year-over-year in 2023 to approximately 263 mtpa. This uptick was largely due to an approximately 8.4 mtpa year-over-year growth in South and Southeast Asia’s demand and a modest rebound in China’s economy, which resulted in approximately 12% or 7.5 mtpa increase in LNG imports into the
35

Table of Contents
country. In Europe, despite continued declines in gas demand, LNG imports were flat year-over-year as pipeline flows from Russia to the EU remained low at 27 billion cubic meters (“Bcm”), down 36 Bcm or 57% year-over-year.

The market dynamics brought on by the need to displace and replace Russian gas into Europe in 2023 resulted in a notable uptick in long-term LNG contracting and a push for LNG project FIDs. Commercial activity in 2023 continued to build on last year’s momentum with executed long-term SPAs in the U.S. reaching approximately 23 mtpa for the year, of which our SPAs and IPM agreements totaled approximately 6.5 mtpa. This contractual momentum over the past two years led to the positive FID of nearly 40 mtpa of U.S. LNG capacity in 2023, and we anticipate that a portion of these contracts will support our future growth.

Despite the global impacts of the Russia-Ukraine war, we do not believe we have significant exposure to adverse direct or indirect impacts of the war, as we do not conduct business in Russia and refrain from business dealings with Russian entities. Additionally, we are not aware of any specific adverse direct or indirect effects of the Russia-Ukraine war or the Israel-Hamas war on our supply chain. Consequently, we believe we are well positioned to help meet the increased demand of our international LNG customers to overcome their supply shortages.

Results of Operations

Consolidated results of operations

Year Ended December 31,
(in millions, except per share data)20232022Variance
Revenues
LNG revenues$19,569 $31,804 $(12,235)
Regasification revenues135 1,068 (933)
Other revenues690 556 134 
Total revenues20,394 33,428 (13,034)
Operating costs and expenses
Cost of sales (excluding items shown separately below)1,356 25,632 (24,276)
Operating and maintenance expense1,835 1,681 154 
Selling, general and administrative expense474 416 58 
Depreciation and amortization expense1,196 1,119 77 
Other44 21 23 
Total operating costs and expenses4,905 28,869 (23,964)
Income from operations15,489 4,559 10,930 
Other income (expense)
Interest expense, net of capitalized interest(1,141)(1,406)265 
Gain (loss) on modification or extinguishment of debt15 (66)81 
Interest and dividend income211 57 154 
Other income (expense), net(50)54 
Total other expense(911)(1,465)554 
Income before income taxes and non-controlling interest14,578 3,094 11,484 
Less: income tax provision2,519 459 2,060 
Net income12,059 2,635 9,424 
Less: net income attributable to non-controlling interest2,178 1,207 971 
Net income attributable to common stockholders$9,881 $1,428 $8,453 
Net income per share attributable to common stockholders—basic
$40.99 $5.69 $35.30 
Net income per share attributable to common stockholders—diluted
$40.72 $5.64 $35.08 

36

Table of Contents
Volumes loaded and recognized from the Liquefaction Projects
Year Ended December 31,
(in TBtu)20232022Variance
Volumes loaded during the current period2,299 2,295 
Volumes loaded during the prior period but recognized during the current period56 49 
Less: volumes loaded during the current period and in transit at the end of the period(37)(56)19 
Total volumes recognized in the current period2,318 2,288 30 

Components of LNG revenues and corresponding LNG volumes delivered
Year Ended December 31,
 20232022Variance
LNG revenues (in millions):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)
$12,820 $20,702 $(7,882)
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements
6,028 10,169 (4,141)
LNG procured from third parties359 760 (401)
Net derivative gains (losses)110 (328)438 
Other revenues252 501 (249)
Total LNG revenues$19,569 $31,804 $(12,235)
Volumes delivered as LNG revenues (in TBtu):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)
2,034 1,926 108 
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements
284 362 (78)
LNG procured from third parties35 29 
Total volumes delivered as LNG revenues2,353 2,317 36 
(1)Long-term agreements include agreements with an initial tenor of 12 months or more.

Net income attributable to common stockholders

The favorable variance of $8.5 billion for the year ended December 31, 2023 as compared to the same period of 2022 was primarily attributable to a favorable variance of $14.4 billion (before tax and the impact of non-controlling interest), from changes in fair value and settlement of derivatives between the periods. The majority of the variance related to derivatives was due to non-cash favorable changes in fair value of our IPM agreements as a result of lower volatility in international gas prices and declines in international forward commodity curves, which changed from a loss of $5.0 billion in the year ended December 31, 2022 to a gain of $7.0 billion in the year ended December 31, 2023.
The favorable variance was partially offset by:
decrease in LNG revenues, net of cost of sales and excluding the effect of derivatives (as further described above), of $2.4 billion, the majority of which was attributable to lower margins on LNG delivered;
unfavorable variance of $2.1 billion in income tax provision due to higher taxable earnings; and
unfavorable variance of $971 million in net income attributable to non-controlling interest due to an increase in CQP’s consolidated net income between the comparable periods.
The following is an additional discussion of the significant drivers of the variance in net income attributable to common stockholders by line item:
Revenues

The decrease of $13.0 billion between the years ended December 31, 2023 and 2022 was primarily attributable to:
$9.1 billion decrease in Henry Hub pricing, to which the majority of our long-term LNG sales contracts are indexed;
37

Table of Contents
decrease in revenues generated by our marketing function of $2.5 billion due to declining international prices and a reduction of volumes sold under short-term agreements; and
decrease in regasification revenues of $933 million due to the accelerated recognition of revenues associated with the termination of one of our TUA agreements in December 2022. See Note 13—Revenues of our Notes to Consolidated Financial Statements for additional information on the termination agreement.
Operating costs and expenses (recoveries)

The $24.0 billion favorable variance between the years ended December 31, 2023 and 2022 was primarily attributable to:
$14.0 billion favorable variance from changes in fair value and settlements of derivatives included in cost of sales, from $6.2 billion of loss in the year ended December 31, 2022 to $7.8 billion of gain in the year ended December 31, 2023, primarily related to non-cash favorable changes in fair value of our IPM agreements as described above under the caption Net income attributable to common stockholders; and
$10.3 billion decrease in cost of sales excluding the effect of derivative changes described above, primarily as a result of $9.6 billion in decreased cost of natural gas feedstock largely due to lower U.S. natural gas prices.
The favorable variance was partially offset by an increase in operating and maintenance expense of $154 million between the comparable periods, which was due to the completion of planned large-scale maintenance activities on two trains at the SPL Project during June 2023, other third party service and maintenance contract costs and natural gas transportation and storage capacity demand charges.

Other income (expense)

The $554 million favorable variance between the years ended December 31, 2023 and 2022 was primarily attributable to:
$265 million decrease in interest expense, net of capitalized interest, primarily as a result of lower debt balances due to $1.2 billion of repayment of debt in 2023, which excludes prepayments associated with debt refinancing;
$154 million increase in interest and dividend income as a result of higher interest income earned on cash and cash equivalents from higher interest rates in 2023; and
$81 million favorable variance in gain (loss) on modification or extinguishment of debt, primarily due to higher losses recognized from the amendment and restatement of CCH’s term loan facility agreement (the “CCH Credit Facility”) and CCH’s working capital facility agreement (the “CCH Working Capital Facility”) during the second quarter of 2022 and the redemption of our 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) during the first quarter of 2022. Further contributing to the favorable variance during the year ended December 31, 2023 was a reduction in premiums paid for the early redemption or repayment of debt principal, as a result of near-maturity debt being redeemed or repaid or repurchased in the open market resulting in lower make-whole payments, as further detailed under Financing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

Income tax provision

The $2.1 billion unfavorable variance between the years ended December 31, 2023 and 2022 was primarily attributable to an increase in pre-tax income.

Our effective tax rate was 17.3% and 14.8% for the years ended December 31, 2023 and 2022, respectively. The effective tax rate for both the years ended December 31, 2023 and 2022 was lower than the statutory rate of 21% primarily due to CQP’s income that is not taxable to us.
In December 2021, the OECD released a framework for Pillar Two model rules, which introduced a global minimum corporate tax rate of 15% for large multinational groups. We are a large multinational group with substantial operations in the U.S. and U.K. The U.K. enacted legislation implementing Pillar Two on July 18, 2023, effective beginning January 1, 2024. The U.S. has not enacted legislation implementing Pillar Two. We are continuing to evaluate the Pillar Two rules and their potential impact on future periods, but we do not expect the rules to have a material impact on our effective tax rate.
38

Table of Contents
Net income attributable to non-controlling interest

The $971 million increase between the years ended December 31, 2023 and 2022 was primarily attributable to $1.8 billion increase in CQP’s consolidated net income between the years ended December 31, 2023 and 2022.

Significant factors affecting our results of operations

Below are significant factors that affect our results of operations.

Gains and losses on derivative instruments

Derivative instruments, which in addition to managing exposure to commodity-related marketing and price risks, are utilized to manage exposure to changing interest rates and foreign exchange volatility, are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of our Liquefaction Supply Derivatives and LNG Trading Derivatives incorporates, as applicable to our natural gas supply contracts, market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.

Commissioning cargoes

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the year ended December 31, 2022, we realized offsets to LNG terminal costs of $204 million corresponding to 15 TBtu attributable to the sale of commissioning cargoes from Train 6 of the SPL Project. We did not have any commissioning cargoes during the year ended December 31, 2023.

Liquidity and Capital Resources

The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of cash and cash equivalents, restricted cash and cash equivalents and available commitments under our credit facilities. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt and equity offerings by us or our subsidiaries. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
39

Table of Contents
December 31, 2023
Cash and cash equivalents (1)$4,066 
Restricted cash and cash equivalents (1)459 
Available commitments under our credit facilities (2):
SPL Revolving Credit Facility
720 
CQP Revolving Credit Facility
1,000 
CCH Credit Facility
3,260 
CCH Working Capital Facility
1,345 
Cheniere’s revolving credit agreement (the “Cheniere Revolving Credit Facility”)
1,250 
Total available commitments under our credit facilities7,575 
Total available liquidity$12,100 
(1)Amounts presented include balances held by our consolidated variable interest entity, CQP, and its subsidiaries, as discussed in Note 9—Non-controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements. As of December 31, 2023, assets of CQP and its subsidiaries, which are included in our Consolidated Balance Sheets, included $575 million of cash and cash equivalents and $56 million of restricted cash and cash equivalents.
(2)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2023. See Note 11—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.
Our liquidity position subsequent to December 31, 2023 will be driven by future sources of liquidity and future cash requirements as further discussed under the caption Future Sources and Uses of Liquidity.

Although our sources and uses of cash are presented below from a consolidated standpoint, SPL, CQP, CCH and Cheniere operate with independent capital structures. Certain restrictions under debt and equity instruments executed by our subsidiaries limit each entity’s ability to distribute cash, including the following:
SPL and CCH are required to deposit all cash received into restricted cash and cash equivalents accounts under certain of their debt agreements. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Projects and other restricted payments. In addition, SPL and CCH’s operating costs are managed by our subsidiaries under affiliate agreements, which may require SPL and CCH to advance cash to the respective affiliates, however the cash remains restricted for operation and construction of the Liquefaction Projects;
CQP is required under its partnership agreement to distribute to unitholders all available cash on hand at the end of a quarter less the amount of any reserves established by its general partner. Beginning with the distribution paid in the second quarter of 2022, quarterly distributions by CQP are currently comprised of a base amount plus a variable amount equal to the remaining available cash per unit, which takes into consideration, among other things, amounts reserved for annual debt repayment and capital allocation goals, anticipated capital expenditures to be funded with cash, and cash reserves to provide for the proper conduct of CQP’s business;
Our 48.6% limited partner interest, 100% general partner interest and incentive distribution rights in CQP limit our right to receive cash held by CQP to the amounts specified by the provisions of CQP’s partnership agreement; and
SPL and CCH are restricted by affirmative and negative covenants included in certain of their debt agreements in their ability to make certain payments, including distributions, unless specific requirements are satisfied.

Despite the restrictions noted above, we believe that sufficient flexibility exists within the Cheniere complex to enable each independent capital structure to meet its currently anticipated cash requirements. The sources of liquidity at SPL, CQP and CCH primarily fund the cash requirements of the respective entity, and any remaining liquidity not subject to restriction, as supplemented by unrestricted liquidity provided by Cheniere Marketing, is available to enable Cheniere to meet its cash requirements.

40

Table of Contents
Future Sources and Uses of Liquidity

The following discussion of our future sources and uses of liquidity includes estimates that reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2023. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
Future Sources of Liquidity under Executed SPAs

As described in Items 1. and 2. Business and Properties, our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Substantially all of our future revenues are contracted under SPAs and because many of these contracts have long-term durations, we are contractually entitled to significant future consideration under these contracts which has not yet been recognized as revenue. This future consideration is, in most cases, not yet legally due to us and was not reflected on our Consolidated Balance Sheets as of December 31, 2023. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following table summarizes our estimate of future material sources of liquidity to be received from executed SPAs as of December 31, 2023 (in billions):
 
Estimated Revenues Under Executed SPAs by Period (1) (2)
 2024
2025 - 2028
ThereafterTotal
LNG revenues (fixed fees)$6.3 $27.1 $77.6 $111.0 
LNG revenues (variable fees) (3)7.0 40.8 140.5 188.3 
Total$13.3 $67.9 $218.1 $299.3 
(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are included in the revenues above when the conditions are considered probable of being met.
(2)LNG revenues exclude revenues from contracts with original expected durations of one year or less. As of December 31, 2023, Cheniere Marketing had short term delivery commitments of approximately 88 TBtu of LNG to be delivered to third party customers in 2024. Fixed fees are fees that are due to us regardless of whether a customer exercises, in certain instances, their contractual right to not take delivery of an LNG cargo under the contract. Variable fees are receivable only in connection with LNG cargoes that are delivered.
(3)LNG revenues (variable fees) reflect the assumption of delivery of all contractual volumes, irrespective of any contractual right of non-delivery. LNG revenues (variable fees) are based on estimated forward prices and basis spreads as of December 31, 2023. The pricing structure of many of our SPA arrangements with our customers incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices.

Through our SPAs and IPM agreements, we have contracted substantially all of the total anticipated production from the Liquefaction Projects through the mid-2030s. The majority of the contracted capacity is comprised of fixed-price, long-term SPAs that SPL and CCL have executed with third parties to sell LNG from the Liquefaction Projects. In addition, we market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL through our integrated marketing function, Cheniere Marketing. Cheniere Marketing has a portfolio of long-, medium- and short-term SPAs to deliver commercial LNG cargoes to locations worldwide. These volumes are expected to be primarily sourced by LNG produced by the Liquefaction Projects but supplemented by volumes procured from other locations worldwide, as needed.

Substantially all of our contracted capacity is from contracts with terms exceeding 10 years. Excluding volumes from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation, our SPAs and IPM agreements had approximately 16 years of weighted average remaining life as of December 31, 2023. Under the SPAs, the customers purchase LNG on either an FOB basis (delivered to the customer at the Sabine Pass LNG Terminal or the Corpus Christi LNG Terminal, as applicable) or a DAT basis (delivered to the customer at their specified LNG receiving terminal) generally for a price consisting of a fixed fee per MMBtu of LNG (a
41

Table of Contents
portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. Certain customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. The variable fees under our SPAs were generally sized with the intention to cover the costs of gas purchases, transportation and liquefaction fuel consumed to produce the LNG to be sold under each such SPA. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of A-, A3 and A- by S&P, Moody’s and Fitch, respectively. A discussion of revenues under our SPAs can be found in Note 13—Revenues of our Notes to Consolidated Financial Statements.

Additional Future Sources of Liquidity

Regasification Revenues

SPLNG has a long-term, third party TUA with TotalEnergies, under which TotalEnergies is required to pay fixed fees of approximately $125 million annually, whether or not it uses the regasification capacity it has reserved. SPL has a partial TUA assignment agreement with TotalEnergies, whereby SPL gained access to substantially all of TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG. Notwithstanding any arrangements between TotalEnergies and SPL, payments required to be made by TotalEnergies to SPLNG will continue to be made by TotalEnergies to SPLNG in accordance with its TUA and we continue to recognize the payments received from TotalEnergies as revenue. Costs incurred by SPL to TotalEnergies under this partial TUA assignment agreement are recognized in operating and maintenance expense. Full discussion of the partial TUA assignment and SPLNG’s revenues under the TUA agreements can be found in Note 13—Revenues of our Notes to Consolidated Financial Statements.

Available Commitments under Credit Facilities

As of December 31, 2023, we had $7.6 billion in available commitments under our credit facilities, as detailed earlier in the table summarizing our available liquidity, subject to compliance with the applicable covenants, to potentially meet liquidity needs. Our credit facilities mature between 2026 and 2029.

Uncontracted Liquefaction Supply

We expect a portion of total production capacity from the Liquefaction Projects that has not yet been contracted under executed agreements as of December 31, 2023 to be available for Cheniere Marketing to market to additional LNG customers. Debottlenecking opportunities and other optimization projects have led to increased run-rate production levels which has increased the production capacity available for Cheniere Marketing to the extent it has not already been contracted to other customers.
Financially Disciplined Growth

Our significant land positions at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal provide potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project. In March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project. The development of these sites or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive FID.

42

Table of Contents
Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts

We are committed to make future cash payments for operations and capital expenditures pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for operations and capital expenditures related to our core operations under executed contracts as of December 31, 2023 (in billions):
Estimated Payments Due Under Executed Contracts by Period (1)
2024
2025 - 2028
ThereafterTotal
Purchase obligations (2):
Natural gas supply agreements (3)$5.8 $20.2 $25.4 $51.4 
Natural gas transportation and storage service agreements (4)0.5 2.0 4.9 7.4 
Capital expenditures1.2 1.7 — 2.9 
Leases (5)0.9 3.0 3.7 7.6 
Total$8.4 $26.9 $34.0 $69.3 
(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023.
(2)Purchase obligations consist of agreements to purchase goods or services that are enforceable and legally binding that specify fixed or minimum quantities to be purchased. We include contracts for which we have an early termination option if the option is not currently expected to be exercised. We include contracts with unsatisfied contractual conditions if the conditions are currently expected to be met.
(3)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2023. Pricing of IPM agreements is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. Global gas market prices are based on estimates as of December 31, 2023 to the extent forward prices are not available and assume the highest price in cases of price optionality available under the agreement. Includes $0.8 billion under natural gas supply agreements with unsatisfied contractual conditions.
(4)Includes $1.3 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements, of which $1.0 billion had unsatisfied contractual conditions.
(5)Leases include payments under (1) operating leases, (2) finance leases, (3) short-term leases and (4) vessel time charters that were executed as of December 31, 2023 but will commence in the future. Certain of our leases also contain variable payments, such as inflation, which are not included above unless the contract terms require in-substance fixed payments that are, in effect, unavoidable. Payments during renewal options that are exercisable at our sole discretion are included only to the extent that the option is believed to be reasonably certain to be exercised. We subcharter certain LNG vessels while retaining our existing obligation under the original charter. Future income associated with our subcharters was $510 million, inclusive of, as described in Note 12—Leases of our Notes to Consolidated Financial Statements, $163 million qualifying as subleases.

Natural Gas Supply, Transportation and Storage Service Agreements

We have secured natural gas feedstock for the CCL Project and the SPL Project through long-term natural gas supply agreements, including IPM agreements. Under our IPM agreements, we pay for natural gas feedstock based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. While IPM agreements are not revenue contracts for accounting purposes, the payment structure for the purchase of natural gas under the IPM agreements generates a take-or-pay style fixed liquefaction fee, assuming that LNG produced from the natural gas feedstock is subsequently sold at a price approximating the global gas market price paid for the natural gas feedstock purchase.

As of December 31, 2023, we have secured approximately 82% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Projects during 2024. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2024. Natural gas supply is generally secured on an indexed pricing basis plus a fixed fee, with title transfer occurring upon receipt of the commodity. As further described in the LNG Revenues section above, the pricing structure of our SPA arrangements with our customers often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices. Inclusive of amounts under contracts with unsatisfied contractual conditions that are currently considered probable of being met and exclusive of extension options that were uncertain to be taken as of December 31, 2023, we have secured up
43

Table of Contents
to 12,794 TBtu of natural gas feedstock through agreements with remaining fixed terms of up to approximately 15 years. A discussion of our natural gas supply and IPM agreements can be found in Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements.

To ensure that we are able to transport natural gas feedstock to the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal, we have entered into transportation precedent and other agreements to secure firm pipeline transportation capacity from interstate and intrastate pipeline companies. We have also entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Projects.

Capital Expenditures

We enter into lump sum turnkey contracts with third party contractors for the EPC of our Liquefaction Projects. The future capital expenditures included in the table above primarily consist of fixed costs under the Bechtel EPC contract for the Corpus Christi Stage 3 Project, in which Bechtel charges a lump sum and generally bears project cost, schedule and performance risks unless certain specified events occurred, in which case Bechtel causes us to enter into a change order, or we agree with Bechtel to a change order. In addition to amounts presented in the table above, we expect to incur ongoing capital expenditures to maintain our facilities and other assets, as well as to optimize our existing assets and purchase new assets that are intended to grow our productive capacity. See Financially Disciplined Growth section for further discussion.

Corpus Christi Stage 3 Project

The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2023:
Overall project completion percentage51.4%
Completion percentage of:
Engineering83.7%
Procurement72.2%
Subcontract work66.9%
Construction11.1%
Date of expected substantial completion2Q/3Q 2025 - 2H 2026

Leases

Our obligations under our lease arrangements primarily consist of LNG vessel time charters with terms of up to 15 years to ensure delivery of cargoes sold on a DAT basis. We have also entered into leases for the use of tug vessels, office space, marine equipment and facilities and land sites. A discussion of our lease obligations can be found in Note 12—Leases of our Notes to Consolidated Financial Statements.

Additional Future Cash Requirements for Operations and Capital Expenditures

Corporate Activities

We are required to maintain corporate and general and administrative functions to serve our business activities. During the year ended December 31, 2023, selling, general and administrative expense was $0.5 billion, a portion of which was related to leases for office space, which is included in the table of cash requirements for operations and capital expenditures under executed contracts above.

Income Tax

Because the currently enacted CAMT may accelerate or cause volatility in our cash tax payments attributable to variability in AFSI, our cash tax payments may fluctuate over time, influenced by both AFSI variability and the resulting impact of the CAMT on other tax benefits, including potential near-term deferral of the realization of our existing NOL carryforwards. This could result in higher cash tax payments in the near-term relative to the year ended December 31, 2023. Additionally, our cash tax payments may be substantially lower in the periods that the Corpus Christi Stage 3 Project is placed into service due to anticipated tax depreciation allowances from the project. Thus, the ongoing interplay between the CAMT,
44

Table of Contents
the utilization of our existing NOLs and bonus depreciation eligibility of our Corpus Christi Stage 3 Project is expected to cause volatility in our cash tax payments. See the risk Additions or changes in tax laws and regulations could potentially affect our financial results or liquidity under Risks Relating to Our Financial Matters in Item 1A. Risk Factors.

Financially Disciplined Growth

The FID of any expansion projects will result in additional cash requirements to fund the construction and operations of such projects in excess of our current contractual obligations under executed contracts discussed above. However, in connection with reaching FID, we may be required to secure financing to meet the cash needs that such project will initially require, in support of commercializing the project.

Beyond the Corpus Christi Stage 3 Project, our significant land positions at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal provide potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. We expect that any potential future expansion at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal would increase cash requirements to support expanded operations, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.

Future Cash Requirements for Financing under Executed Contracts

We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2023 (in billions):
 Estimated Payments Due Under Executed Contracts by Period (1)
 2024
2025 - 2028
ThereafterTotal
Debt$0.3 $11.1 $12.5 $23.9 
Interest payments1.3 3.3 1.8 6.4 
Total$1.6 $14.4 $14.3 $30.3 
(1)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in effect at December 31, 2023. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity.

Debt

As of December 31, 2023, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $23.9 billion and credit facilities with no outstanding loan balances. As of December 31, 2023, each of our issuers was in compliance with all covenants related to their respective debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 11—Debt of our Notes to Consolidated Financial Statements.

Interest

As of December 31, 2023, our senior notes had a weighted average contractual interest rate of 4.73%. All of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through amendments or replacements of previous credit facilities. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.075% to 0.525%, subject to change based on the applicable entity’s credit rating. Issued letters of credit under our credit facilities are subject to letter of credit fees ranging from 1.000% to 2.200%, subject to change based on the applicable entity’s credit rating. We had $435 million aggregate amount of issued letters of credit under our credit facilities as of December 31, 2023.
45

Table of Contents
Additional Future Cash Requirements for Financing

CQP Distributions

CQP is required by its partnership agreement to, within 45 days after the end of each quarter, distribute to unitholders all available cash at the end of a quarter less the amount of any reserves established by its general partner. We own a 48.6% limited partner interest in CQP in the form of 239.9 million common units, 100% of the general partner interest and 100% of the incentive distribution rights, with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. During the year ended December 31, 2023, $1.0 billion in distributions were paid to our non-controlling interests.

Capital Allocation Plan

In September 2022, our Board approved a revised comprehensive long-term capital allocation plan. Pursuant to the revised capital allocation plan, on September 12, 2022 our Board authorized an increase in the existing share repurchase program by $4.0 billion for an additional three years, beginning on October 1, 2022. As of December 31, 2023, we had up to $2.1 billion available under the share repurchase program. The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by management based on market conditions and other factors. During the year ended December 31, 2023, we repurchased a total of 9.5 million shares of our common stock for $1.5 billion at a weighted average price per share of $155.50. A discussion of our share repurchase program can be found in Item 5. Market for Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchase of Equity Securities.

A further aspect of our capital allocation plan is to lower our long-term leverage target through debt paydown to approximately 4x, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of our indebtedness, including senior notes of SPL, CQP, CCH and Cheniere. The timing and amount of any paydown of our indebtedness will be determined by management based on market conditions and other factors. During the year ended December 31, 2023, we used $1.2 billion of available cash to reduce our outstanding indebtedness, all of which was pursuant to our capital allocation plan.

The capital allocation plan also includes a targeted annual dividend growth rate of approximately 10% through Corpus Christi Stage 3 Project construction. On January 26, 2024, we declared a quarterly dividend of $0.435 per share of common stock that is payable on February 23, 2024 to stockholders of record as of the close of business on February 6, 2024.

Financially Disciplined Growth

To the extent that liquefaction capacity at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal is expanded beyond the Liquefaction Projects, such as the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, we expect that additional financing would be used to fund construction of the expansion.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash and cash equivalents (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table. 
Year Ended December 31,
20232022
Net cash provided by operating activities$8,418 $10,523 
Net cash used in investing activities(2,202)(1,844)
Net cash used in financing activities(4,180)(8,014)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents
Net increase in cash, cash equivalents and restricted cash and cash equivalents
$2,038 $670 
46

Table of Contents
Operating Cash Flows

The $2.1 billion decrease between the periods was primarily related to lower cash receipts from the sale of LNG cargoes due to lower pricing per MMBtu as a result of decreased pricing and a reduction of volumes sold under short-term agreements, as well as a decrease in regasification revenues. A discussion of our revenues, including LNG and regasification revenues, can be found in Note 13—Revenues of our Notes to Consolidated Financial Statements. The decrease was partially offset by lower cash outflows for natural gas feedstock, mostly due to lower U.S. natural gas prices.

As described in Future Sources and Uses of Liquidity, our future operating cash flows will be impacted by CAMT, which may result in greater volatility in our cash tax payments, including potentially higher cash payments in the near-term relative to the year ended December 31, 2023. See Future Sources and Uses of Liquidity for additional discussion.

Investing Cash Flows

Our investing net cash outflows in both years primarily were for the construction costs for the Liquefaction Projects. The $358 million increase in 2023 compared to 2022 was primarily due to $1.5 billion of cash outflows during the year ended December 31, 2023 related to construction of the Corpus Christi Stage 3 Project following our issuance of full notice to proceed to Bechtel in June 2022 compared to $880 million in the comparable period of 2022, partially offset by a decrease in spend due to the completion of Train 6 of the SPL Project in February 2022. We expect to incur a similar level of capital expenditures in the upcoming year as construction work progresses on the Corpus Christi Stage 3 Project. During the year ended December 31, 2023, we also made investments in infrastructure expected to support the development, construction and operations of the Corpus Christi Stage 3 Project, including an investment in pipeline capacity for natural gas feedstock. Also during the year ended December 31, 2023, we acquired an existing power generation facility located near Corpus Christi, Texas to mitigate power price risk associated with our anticipated increased power load at the Corpus Christi LNG Terminal.

Financing Cash Flows

The following table summarizes our financing activities (in millions):
Year Ended December 31,
20232022
Proceeds from issuances of debt$1,397 $1,575 
Redemptions, repayments and repurchases of debt(2,598)(6,771)
Distributions to non-controlling interest(1,016)(947)
Repurchase of common stock(1,473)(1,373)
Dividends to stockholders(393)(349)
Other, net(97)(149)
Net cash used in financing activities$(4,180)$(8,014)

Debt Issuances

During the year ended December 31, 2023, CQP issued an aggregate principal amount of $1.4 billion of 2033 CQP Senior Notes, the proceeds of which were used, together with cash on hand, to redeem $1.4 billion of the 2024 SPL Senior Notes. Additionally, during the year ended December 31, 2023, SPL purchased $200 million of the 2024 SPL Senior Notes in the open market and redeemed an additional $100 million of the 2024 SPL Senior Notes. As of December 31, 2023, the only bonds maturing in 2024 are the remaining $300 million outstanding of the 2024 SPL Senior Notes. During the year ended December 31, 2022, SPL issued $430 million of 5.900% Senior Secured Amortizing Notes due 2037 and $70 million of 2037 SPL Private Placement Senior Secured Notes, and we had total borrowings of $1.1 billion under our credit facilities. The proceeds from the borrowings during the year ended December 31, 2022, together with cash on hand, were used to redeem or repurchase $6.8 billion of outstanding indebtedness, entirely associated with redemptions of our outstanding notes or repayment of amounts outstanding under our credit facilities.
47

Table of Contents
Debt Redemptions, Repayments and Repurchases

The following table shows the redemptions, repayments and repurchases of debt, including intra-year repayments (in millions):
Year Ended December 31,
20232022
Redemptions, repayments and repurchases of debt
SPL:
2024 SPL Senior Notes
$(1,700)$— 
2023 SPL Senior Notes— (1,500)
SPL Working Capital Facility— (60)
CCH:
CCH Credit Facility— (2,169)
CCH Working Capital Facility— (250)
7.000% Senior Notes due 2024
(498)(752)
5.625% Senior Notes due 2025
— (9)
5.125% Senior Notes due 2027
(69)(230)
3.700% Senior Notes due 2029
(237)(138)
2.742% Senior Notes due 2039(94)— 
3.788% weighted average Senior Notes rate due 2039
— (88)
Cheniere:
2045 Cheniere Convertible Senior Notes— (500)
Cheniere Revolving Credit Facility— (575)
4.625% Senior Notes due 2028— (500)
Total redemptions, repayments and repurchases of debt$(2,598)$(6,771)

Non-Controlling Interest Distributions

We own a 48.6% limited partner interest in CQP with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. Distributions of $1.0 billion and $947 million were paid during the years ended December 31, 2023 and 2022, respectively, to non-controlling interests.
Repurchase of Common Stock

During the years ended December 31, 2023 and 2022, we paid $1.5 billion and $1.4 billion to repurchase 9.5 million and 9.4 million shares of our common stock, respectively, under our share repurchase program. As of December 31, 2023, we had approximately $2.1 billion remaining under our share repurchase program.
Cash Dividends to Stockholders

During the year ended December 31, 2023, we paid aggregate dividends of $1.62 per share of common stock, for a total of $393 million. We paid aggregate dividends of $1.385 per share of common stock, for a total of $349 million during the year ended December 31, 2022.

On January 26, 2024, we declared a quarterly dividend of $0.435 per share of common stock that is payable on February 23, 2024 to stockholders of record as of the close of business on February 6, 2024.
Summary of Critical Accounting Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments. Changes in facts and circumstances or additional information may result in revised
48

Table of Contents
estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.

Fair Value of Level 3 Physical Liquefaction Supply Derivatives

All of our derivative instruments are recorded at fair value, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. We record changes in the fair value of our derivative positions through earnings, based on the value for which the derivative instrument could be exchanged between willing parties. Valuation of our physical liquefaction supply derivative contracts is often developed through the use of internal models which includes significant unobservable inputs representing Level 3 fair value measurements as further described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies. In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.
As applicable to our natural gas supply contracts, our fair value estimates incorporate market participant-based assumptions pertaining to applicable contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.

Additionally, the valuation of certain physical liquefaction supply derivatives requires significant judgment in estimating underlying forward commodity curves due to periods of unobservability or limited liquidity. Such valuations are more susceptible to variability particularly when markets are volatile. Provided below are the changes in fair value from valuation of instruments valued through the use of internal models which incorporate significant unobservable inputs for the years ended December 31, 2023 and 2022 (in millions), which entirely consisted of physical liquefaction supply derivatives. The changes in fair value shown are limited to instruments still held at the end of each respective period.
Year Ended December 31,
20232022
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period
$5,700 $(6,493)

The changes in fair value on instruments held at the end of both years are primarily attributed to a significant variance in the estimated and observable forward international LNG commodity prices on our IPM agreements during the years ended December 31, 2023 and 2022.
The estimated fair value of level 3 derivatives recognized in our Consolidated Balance Sheets as of December 31, 2023 and 2022 amounted to a liability of $2.2 billion and $9.9 billion, respectively, consisting entirely of physical liquefaction supply derivatives.

The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a material change in the estimated fair value could occur in the near future, particularly as it relates to commodity prices given the level of volatility in the current year. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for further analysis of the sensitivity of the fair value of our derivatives to hypothetical changes in underlying prices.
49

Table of Contents
Recent Accounting Standards

For a summary of recently issued accounting standards, see Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.
ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Marketing and Trading Commodity Price Risk

We have commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project and the CCL Project, and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”). We have also entered into physical and financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives and the LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location and a 10% change in the commodity price for LNG, respectively, as follows (in millions):
December 31, 2023December 31, 2022
Fair Value Change in Fair ValueFair Value Change in Fair Value
Liquefaction Supply Derivatives$(2,117)$1,526 $(10,019)$2,249 
LNG Trading Derivatives10 12 (46)15 

See Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our commodity derivative instruments.

50

Table of Contents
ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES