0000003570false--12-312020Q31LIBOR or base rateLIBOR or base rateLIBOR or base rateLIBOR or base rateLIBOR or base rateLIBOR or base rate00000035702020-01-012020-09-30xbrli:shares00000035702020-10-30iso4217:USD00000035702020-09-3000000035702019-12-31iso4217:USDxbrli:shares0000003570us-gaap:CommonStockMember2020-09-300000003570us-gaap:CommonStockMember2019-12-310000003570us-gaap:TreasuryStockMember2020-09-300000003570lng:CheniereEnergyPartnersLPMember2020-09-300000003570lng:LiquefiedNaturalGasMember2020-07-012020-09-300000003570lng:LiquefiedNaturalGasMember2019-07-012019-09-300000003570lng:LiquefiedNaturalGasMember2020-01-012020-09-300000003570lng:LiquefiedNaturalGasMember2019-01-012019-09-300000003570lng:RegasificationServiceMember2020-07-012020-09-300000003570lng:RegasificationServiceMember2019-07-012019-09-300000003570lng:RegasificationServiceMember2020-01-012020-09-300000003570lng:RegasificationServiceMember2019-01-012019-09-300000003570us-gaap:ProductAndServiceOtherMember2020-07-012020-09-300000003570us-gaap:ProductAndServiceOtherMember2019-07-012019-09-300000003570us-gaap:ProductAndServiceOtherMember2020-01-012020-09-300000003570us-gaap:ProductAndServiceOtherMember2019-01-012019-09-3000000035702020-07-012020-09-3000000035702019-07-012019-09-3000000035702019-01-012019-09-300000003570us-gaap:TreasuryStockMember2019-12-310000003570us-gaap:AdditionalPaidInCapitalMember2019-12-310000003570us-gaap:RetainedEarningsMember2019-12-310000003570us-gaap:NoncontrollingInterestMember2019-12-310000003570us-gaap:CommonStockMember2020-01-012020-03-310000003570us-gaap:TreasuryStockMember2020-01-012020-03-310000003570us-gaap:AdditionalPaidInCapitalMember2020-01-012020-03-310000003570us-gaap:RetainedEarningsMember2020-01-012020-03-310000003570us-gaap:NoncontrollingInterestMember2020-01-012020-03-3100000035702020-01-012020-03-310000003570us-gaap:CommonStockMember2020-03-310000003570us-gaap:TreasuryStockMember2020-03-310000003570us-gaap:AdditionalPaidInCapitalMember2020-03-310000003570us-gaap:RetainedEarningsMember2020-03-310000003570us-gaap:NoncontrollingInterestMember2020-03-3100000035702020-03-310000003570us-gaap:CommonStockMember2020-04-012020-06-300000003570us-gaap:TreasuryStockMember2020-04-012020-06-300000003570us-gaap:AdditionalPaidInCapitalMember2020-04-012020-06-300000003570us-gaap:RetainedEarningsMember2020-04-012020-06-300000003570us-gaap:NoncontrollingInterestMember2020-04-012020-06-3000000035702020-04-012020-06-300000003570us-gaap:CommonStockMember2020-06-300000003570us-gaap:TreasuryStockMember2020-06-300000003570us-gaap:AdditionalPaidInCapitalMember2020-06-300000003570us-gaap:RetainedEarningsMember2020-06-300000003570us-gaap:NoncontrollingInterestMember2020-06-3000000035702020-06-300000003570us-gaap:CommonStockMember2020-07-012020-09-300000003570us-gaap:TreasuryStockMember2020-07-012020-09-300000003570us-gaap:AdditionalPaidInCapitalMember2020-07-012020-09-300000003570us-gaap:RetainedEarningsMember2020-07-012020-09-300000003570us-gaap:NoncontrollingInterestMember2020-07-012020-09-300000003570us-gaap:AdditionalPaidInCapitalMember2020-09-300000003570us-gaap:RetainedEarningsMember2020-09-300000003570us-gaap:NoncontrollingInterestMember2020-09-300000003570us-gaap:CommonStockMember2018-12-310000003570us-gaap:TreasuryStockMember2018-12-310000003570us-gaap:AdditionalPaidInCapitalMember2018-12-310000003570us-gaap:RetainedEarningsMember2018-12-310000003570us-gaap:NoncontrollingInterestMember2018-12-3100000035702018-12-310000003570us-gaap:CommonStockMember2019-01-012019-03-310000003570us-gaap:TreasuryStockMember2019-01-012019-03-310000003570us-gaap:AdditionalPaidInCapitalMember2019-01-012019-03-310000003570us-gaap:RetainedEarningsMember2019-01-012019-03-310000003570us-gaap:NoncontrollingInterestMember2019-01-012019-03-3100000035702019-01-012019-03-310000003570us-gaap:CommonStockMember2019-03-310000003570us-gaap:TreasuryStockMember2019-03-310000003570us-gaap:AdditionalPaidInCapitalMember2019-03-310000003570us-gaap:RetainedEarningsMember2019-03-310000003570us-gaap:NoncontrollingInterestMember2019-03-3100000035702019-03-310000003570us-gaap:CommonStockMember2019-04-012019-06-300000003570us-gaap:TreasuryStockMember2019-04-012019-06-300000003570us-gaap:AdditionalPaidInCapitalMember2019-04-012019-06-300000003570us-gaap:RetainedEarningsMember2019-04-012019-06-300000003570us-gaap:NoncontrollingInterestMember2019-04-012019-06-3000000035702019-04-012019-06-300000003570us-gaap:CommonStockMember2019-06-300000003570us-gaap:TreasuryStockMember2019-06-300000003570us-gaap:AdditionalPaidInCapitalMember2019-06-300000003570us-gaap:RetainedEarningsMember2019-06-300000003570us-gaap:NoncontrollingInterestMember2019-06-3000000035702019-06-300000003570us-gaap:CommonStockMember2019-07-012019-09-300000003570us-gaap:TreasuryStockMember2019-07-012019-09-300000003570us-gaap:AdditionalPaidInCapitalMember2019-07-012019-09-300000003570us-gaap:RetainedEarningsMember2019-07-012019-09-300000003570us-gaap:NoncontrollingInterestMember2019-07-012019-09-300000003570us-gaap:CommonStockMember2019-09-300000003570us-gaap:TreasuryStockMember2019-09-300000003570us-gaap:AdditionalPaidInCapitalMember2019-09-300000003570us-gaap:RetainedEarningsMember2019-09-300000003570us-gaap:NoncontrollingInterestMember2019-09-3000000035702019-09-30lng:unitlng:trains0000003570lng:SabinePassLNGTerminalMember2020-01-012020-09-30lng:milliontonnesutr:Ylng:itemutr:mi0000003570lng:CreoleTrailPipelineMember2020-01-012020-09-30xbrli:pure0000003570lng:CheniereEnergyPartnersLPMember2020-01-012020-09-300000003570lng:CorpusChristiLNGTerminalMember2020-01-012020-09-300000003570lng:CorpusChristiPipelineMember2020-01-012020-09-300000003570lng:CorpusChristiLNGTerminalExpansionMembersrt:MaximumMember2020-01-012020-09-300000003570lng:CorpusChristiLNGTerminalExpansionMember2020-01-012020-09-300000003570lng:SPLProjectMember2020-09-300000003570lng:SPLProjectMember2019-12-310000003570lng:CCLProjectMember2020-09-300000003570lng:CCLProjectMember2019-12-310000003570lng:SubsidiaryCashMember2020-09-300000003570lng:SubsidiaryCashMember2019-12-310000003570lng:SabinePassLiquefactionAndCorpusChristiLiquefactionMember2020-09-300000003570lng:SabinePassLiquefactionAndCorpusChristiLiquefactionMember2019-12-310000003570lng:CheniereMarketingLLCMember2020-09-300000003570lng:CheniereMarketingLLCMember2019-12-310000003570lng:NaturalGasInventoryMember2020-09-300000003570lng:NaturalGasInventoryMember2019-12-310000003570lng:LiquefiedNaturalGasInventoryMember2020-09-300000003570lng:LiquefiedNaturalGasInventoryMember2019-12-310000003570lng:LiquefiedNaturalGasInTransitInventoryMember2020-09-300000003570lng:LiquefiedNaturalGasInTransitInventoryMember2019-12-310000003570lng:MaterialsAndOtherInventoryMember2020-09-300000003570lng:MaterialsAndOtherInventoryMember2019-12-310000003570lng:LngTerminalMember2020-09-300000003570lng:LngTerminalMember2019-12-310000003570lng:LngSiteAndRelatedCostsNetMember2020-09-300000003570lng:LngSiteAndRelatedCostsNetMember2019-12-310000003570us-gaap:ConstructionInProgressMember2020-09-300000003570us-gaap:ConstructionInProgressMember2019-12-310000003570lng:LngTerminalCostsMember2020-09-300000003570lng:LngTerminalCostsMember2019-12-310000003570us-gaap:OfficeEquipmentMember2020-09-300000003570us-gaap:OfficeEquipmentMember2019-12-310000003570us-gaap:FurnitureAndFixturesMember2020-09-300000003570us-gaap:FurnitureAndFixturesMember2019-12-310000003570us-gaap:SoftwareAndSoftwareDevelopmentCostsMember2020-09-300000003570us-gaap:SoftwareAndSoftwareDevelopmentCostsMember2019-12-310000003570us-gaap:LeaseholdImprovementsMember2020-09-300000003570us-gaap:LeaseholdImprovementsMember2019-12-310000003570us-gaap:LandMember2020-09-300000003570us-gaap:LandMember2019-12-310000003570us-gaap:OtherCapitalizedPropertyPlantAndEquipmentMember2020-09-300000003570us-gaap:OtherCapitalizedPropertyPlantAndEquipmentMember2019-12-310000003570lng:FixedAssetsMember2020-09-300000003570lng:FixedAssetsMember2019-12-310000003570us-gaap:AssetsHeldUnderCapitalLeasesMember2020-09-300000003570us-gaap:AssetsHeldUnderCapitalLeasesMember2019-12-310000003570lng:CCHInterestRateDerivativesMemberus-gaap:FairValueInputsLevel1Member2020-09-300000003570lng:CCHInterestRateDerivativesMemberus-gaap:FairValueInputsLevel2Member2020-09-300000003570us-gaap:FairValueInputsLevel3Memberlng:CCHInterestRateDerivativesMember2020-09-300000003570lng:CCHInterestRateDerivativesMember2020-09-300000003570lng:CCHInterestRateDerivativesMemberus-gaap:FairValueInputsLevel1Member2019-12-310000003570lng:CCHInterestRateDerivativesMemberus-gaap:FairValueInputsLevel2Member2019-12-310000003570us-gaap:FairValueInputsLevel3Memberlng:CCHInterestRateDerivativesMember2019-12-310000003570lng:CCHInterestRateDerivativesMember2019-12-310000003570us-gaap:FairValueInputsLevel1Memberlng:CCHInterestRateForwardStartDerivativesMember2020-09-300000003570us-gaap:FairValueInputsLevel2Memberlng:CCHInterestRateForwardStartDerivativesMember2020-09-300000003570us-gaap:FairValueInputsLevel3Memberlng:CCHInterestRateForwardStartDerivativesMember2020-09-300000003570lng:CCHInterestRateForwardStartDerivativesMember2020-09-300000003570us-gaap:FairValueInputsLevel1Memberlng:CCHInterestRateForwardStartDerivativesMember2019-12-310000003570us-gaap:FairValueInputsLevel2Memberlng:CCHInterestRateForwardStartDerivativesMember2019-12-310000003570us-gaap:FairValueInputsLevel3Memberlng:CCHInterestRateForwardStartDerivativesMember2019-12-310000003570lng:CCHInterestRateForwardStartDerivativesMember2019-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:FairValueInputsLevel1Member2020-09-300000003570us-gaap:PriceRiskDerivativeMemberus-gaap:FairValueInputsLevel2Member2020-09-300000003570us-gaap:FairValueInputsLevel3Memberus-gaap:PriceRiskDerivativeMember2020-09-300000003570us-gaap:PriceRiskDerivativeMember2020-09-300000003570us-gaap:PriceRiskDerivativeMemberus-gaap:FairValueInputsLevel1Member2019-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:FairValueInputsLevel2Member2019-12-310000003570us-gaap:FairValueInputsLevel3Memberus-gaap:PriceRiskDerivativeMember2019-12-310000003570us-gaap:PriceRiskDerivativeMember2019-12-310000003570lng:LNGTradingDerivativeMemberus-gaap:FairValueInputsLevel1Member2020-09-300000003570lng:LNGTradingDerivativeMemberus-gaap:FairValueInputsLevel2Member2020-09-300000003570lng:LNGTradingDerivativeMemberus-gaap:FairValueInputsLevel3Member2020-09-300000003570lng:LNGTradingDerivativeMember2020-09-300000003570lng:LNGTradingDerivativeMemberus-gaap:FairValueInputsLevel1Member2019-12-310000003570lng:LNGTradingDerivativeMemberus-gaap:FairValueInputsLevel2Member2019-12-310000003570lng:LNGTradingDerivativeMemberus-gaap:FairValueInputsLevel3Member2019-12-310000003570lng:LNGTradingDerivativeMember2019-12-310000003570us-gaap:ForeignExchangeContractMemberus-gaap:FairValueInputsLevel1Member2020-09-300000003570us-gaap:ForeignExchangeContractMemberus-gaap:FairValueInputsLevel2Member2020-09-300000003570us-gaap:FairValueInputsLevel3Memberus-gaap:ForeignExchangeContractMember2020-09-300000003570us-gaap:ForeignExchangeContractMember2020-09-300000003570us-gaap:ForeignExchangeContractMemberus-gaap:FairValueInputsLevel1Member2019-12-310000003570us-gaap:ForeignExchangeContractMemberus-gaap:FairValueInputsLevel2Member2019-12-310000003570us-gaap:FairValueInputsLevel3Memberus-gaap:ForeignExchangeContractMember2019-12-310000003570us-gaap:ForeignExchangeContractMember2019-12-310000003570us-gaap:FairValueInputsLevel3Memberlng:PhysicalLiquefactionSupplyDerivativesMember2020-09-300000003570us-gaap:FairValueInputsLevel3Memberlng:PhysicalLiquefactionSupplyDerivativesMemberus-gaap:MarketApproachValuationTechniqueMembersrt:MinimumMember2020-01-012020-09-300000003570us-gaap:FairValueInputsLevel3Memberlng:PhysicalLiquefactionSupplyDerivativesMemberus-gaap:MarketApproachValuationTechniqueMembersrt:MaximumMember2020-01-012020-09-300000003570us-gaap:FairValueInputsLevel3Memberlng:PhysicalLiquefactionSupplyDerivativesMemberus-gaap:MarketApproachValuationTechniqueMembersrt:WeightedAverageMember2020-01-012020-09-300000003570us-gaap:ValuationTechniqueOptionPricingModelMemberus-gaap:FairValueInputsLevel3Memberlng:PhysicalLiquefactionSupplyDerivativesMembersrt:MinimumMember2020-01-012020-09-300000003570us-gaap:ValuationTechniqueOptionPricingModelMemberus-gaap:FairValueInputsLevel3Memberlng:PhysicalLiquefactionSupplyDerivativesMembersrt:MaximumMember2020-01-012020-09-300000003570us-gaap:ValuationTechniqueOptionPricingModelMemberus-gaap:FairValueInputsLevel3Memberlng:PhysicalLiquefactionSupplyDerivativesMembersrt:WeightedAverageMember2020-01-012020-09-300000003570lng:PhysicalLiquefactionSupplyDerivativesMember2020-06-300000003570lng:PhysicalLiquefactionSupplyDerivativesMember2019-06-300000003570lng:PhysicalLiquefactionSupplyDerivativesMember2019-12-310000003570lng:PhysicalLiquefactionSupplyDerivativesMember2018-12-310000003570lng:PhysicalLiquefactionSupplyDerivativesMember2020-07-012020-09-300000003570lng:PhysicalLiquefactionSupplyDerivativesMember2019-07-012019-09-300000003570lng:PhysicalLiquefactionSupplyDerivativesMember2020-01-012020-09-300000003570lng:PhysicalLiquefactionSupplyDerivativesMember2019-01-012019-09-300000003570lng:PhysicalLiquefactionSupplyDerivativesMember2020-09-300000003570lng:PhysicalLiquefactionSupplyDerivativesMember2019-09-300000003570us-gaap:InterestRateContractMember2020-01-012020-09-300000003570lng:CCHInterestRateDerivativesMember2020-01-012020-09-300000003570lng:CCHInterestRateDerivativesMemberus-gaap:DerivativeFinancialInstrumentsLiabilitiesMember2020-09-300000003570us-gaap:DerivativeFinancialInstrumentsLiabilitiesMemberlng:CCHInterestRateForwardStartDerivativesMember2020-09-300000003570us-gaap:InterestRateContractMemberus-gaap:DerivativeFinancialInstrumentsLiabilitiesMember2020-09-300000003570lng:CCHInterestRateDerivativesMemberus-gaap:DerivativeFinancialInstrumentsLiabilitiesMember2019-12-310000003570us-gaap:DerivativeFinancialInstrumentsLiabilitiesMemberlng:CCHInterestRateForwardStartDerivativesMember2019-12-310000003570us-gaap:InterestRateContractMemberus-gaap:DerivativeFinancialInstrumentsLiabilitiesMember2019-12-310000003570lng:CCHInterestRateDerivativesMemberlng:NoncurrentDerivativeLiabilitiesMember2020-09-300000003570lng:NoncurrentDerivativeLiabilitiesMemberlng:CCHInterestRateForwardStartDerivativesMember2020-09-300000003570us-gaap:InterestRateContractMemberlng:NoncurrentDerivativeLiabilitiesMember2020-09-300000003570lng:CCHInterestRateDerivativesMemberlng:NoncurrentDerivativeLiabilitiesMember2019-12-310000003570lng:NoncurrentDerivativeLiabilitiesMemberlng:CCHInterestRateForwardStartDerivativesMember2019-12-310000003570us-gaap:InterestRateContractMemberlng:NoncurrentDerivativeLiabilitiesMember2019-12-310000003570us-gaap:InterestRateContractMember2020-09-300000003570us-gaap:InterestRateContractMember2019-12-310000003570lng:CCHInterestRateDerivativesMemberus-gaap:GainLossOnDerivativeInstrumentsMember2020-07-012020-09-300000003570lng:CCHInterestRateDerivativesMemberus-gaap:GainLossOnDerivativeInstrumentsMember2019-07-012019-09-300000003570lng:CCHInterestRateDerivativesMemberus-gaap:GainLossOnDerivativeInstrumentsMember2020-01-012020-09-300000003570lng:CCHInterestRateDerivativesMemberus-gaap:GainLossOnDerivativeInstrumentsMember2019-01-012019-09-300000003570us-gaap:GainLossOnDerivativeInstrumentsMemberlng:CCHInterestRateForwardStartDerivativesMember2020-07-012020-09-300000003570us-gaap:GainLossOnDerivativeInstrumentsMemberlng:CCHInterestRateForwardStartDerivativesMember2019-07-012019-09-300000003570us-gaap:GainLossOnDerivativeInstrumentsMemberlng:CCHInterestRateForwardStartDerivativesMember2020-01-012020-09-300000003570us-gaap:GainLossOnDerivativeInstrumentsMemberlng:CCHInterestRateForwardStartDerivativesMember2019-01-012019-09-300000003570lng:PhysicalLiquefactionSupplyDerivativesMembersrt:MaximumMember2020-01-012020-09-300000003570us-gaap:CommodityContractMember2020-01-012020-09-300000003570us-gaap:DerivativeFinancialInstrumentsAssetsMemberus-gaap:PriceRiskDerivativeMember2020-09-300000003570us-gaap:DerivativeFinancialInstrumentsAssetsMemberlng:LNGTradingDerivativeMember2020-09-300000003570us-gaap:DerivativeFinancialInstrumentsAssetsMemberus-gaap:CommodityContractMember2020-09-300000003570us-gaap:DerivativeFinancialInstrumentsAssetsMemberus-gaap:PriceRiskDerivativeMember2019-12-310000003570us-gaap:DerivativeFinancialInstrumentsAssetsMemberlng:LNGTradingDerivativeMember2019-12-310000003570us-gaap:DerivativeFinancialInstrumentsAssetsMemberus-gaap:CommodityContractMember2019-12-310000003570us-gaap:PriceRiskDerivativeMemberlng:NoncurrentDerivativeAssetsMember2020-09-300000003570lng:LNGTradingDerivativeMemberlng:NoncurrentDerivativeAssetsMember2020-09-300000003570lng:NoncurrentDerivativeAssetsMemberus-gaap:CommodityContractMember2020-09-300000003570us-gaap:PriceRiskDerivativeMemberlng:NoncurrentDerivativeAssetsMember2019-12-310000003570lng:LNGTradingDerivativeMemberlng:NoncurrentDerivativeAssetsMember2019-12-310000003570lng:NoncurrentDerivativeAssetsMemberus-gaap:CommodityContractMember2019-12-310000003570us-gaap:CommodityContractMember2020-09-300000003570us-gaap:CommodityContractMember2019-12-310000003570us-gaap:PriceRiskDerivativeMemberus-gaap:DerivativeFinancialInstrumentsLiabilitiesMember2020-09-300000003570lng:LNGTradingDerivativeMemberus-gaap:DerivativeFinancialInstrumentsLiabilitiesMember2020-09-300000003570us-gaap:DerivativeFinancialInstrumentsLiabilitiesMemberus-gaap:CommodityContractMember2020-09-300000003570us-gaap:PriceRiskDerivativeMemberus-gaap:DerivativeFinancialInstrumentsLiabilitiesMember2019-12-310000003570lng:LNGTradingDerivativeMemberus-gaap:DerivativeFinancialInstrumentsLiabilitiesMember2019-12-310000003570us-gaap:DerivativeFinancialInstrumentsLiabilitiesMemberus-gaap:CommodityContractMember2019-12-310000003570us-gaap:PriceRiskDerivativeMemberlng:NoncurrentDerivativeLiabilitiesMember2020-09-300000003570lng:LNGTradingDerivativeMemberlng:NoncurrentDerivativeLiabilitiesMember2020-09-300000003570lng:NoncurrentDerivativeLiabilitiesMemberus-gaap:CommodityContractMember2020-09-300000003570us-gaap:PriceRiskDerivativeMemberlng:NoncurrentDerivativeLiabilitiesMember2019-12-310000003570lng:LNGTradingDerivativeMemberlng:NoncurrentDerivativeLiabilitiesMember2019-12-310000003570lng:NoncurrentDerivativeLiabilitiesMemberus-gaap:CommodityContractMember2019-12-31lng:tbtu0000003570lng:LNGTradingDerivativeMemberus-gaap:SalesMember2020-07-012020-09-300000003570lng:LNGTradingDerivativeMemberus-gaap:SalesMember2019-07-012019-09-300000003570lng:LNGTradingDerivativeMemberus-gaap:SalesMember2020-01-012020-09-300000003570lng:LNGTradingDerivativeMemberus-gaap:SalesMember2019-01-012019-09-300000003570lng:LNGTradingDerivativeMemberus-gaap:CostOfSalesMember2020-07-012020-09-300000003570lng:LNGTradingDerivativeMemberus-gaap:CostOfSalesMember2019-07-012019-09-300000003570lng:LNGTradingDerivativeMemberus-gaap:CostOfSalesMember2020-01-012020-09-300000003570lng:LNGTradingDerivativeMemberus-gaap:CostOfSalesMember2019-01-012019-09-300000003570us-gaap:PriceRiskDerivativeMemberus-gaap:SalesMember2020-07-012020-09-300000003570us-gaap:PriceRiskDerivativeMemberus-gaap:SalesMember2019-07-012019-09-300000003570us-gaap:PriceRiskDerivativeMemberus-gaap:SalesMember2020-01-012020-09-300000003570us-gaap:PriceRiskDerivativeMemberus-gaap:SalesMember2019-01-012019-09-300000003570us-gaap:PriceRiskDerivativeMemberus-gaap:CostOfSalesMember2020-07-012020-09-300000003570us-gaap:PriceRiskDerivativeMemberus-gaap:CostOfSalesMember2019-07-012019-09-300000003570us-gaap:PriceRiskDerivativeMemberus-gaap:CostOfSalesMember2020-01-012020-09-300000003570us-gaap:PriceRiskDerivativeMemberus-gaap:CostOfSalesMember2019-01-012019-09-300000003570us-gaap:ForeignExchangeContractMember2020-01-012020-09-300000003570us-gaap:DerivativeFinancialInstrumentsAssetsMemberus-gaap:ForeignExchangeContractMember2020-09-300000003570us-gaap:DerivativeFinancialInstrumentsAssetsMemberus-gaap:ForeignExchangeContractMember2019-12-310000003570us-gaap:ForeignExchangeContractMemberus-gaap:DerivativeFinancialInstrumentsLiabilitiesMember2020-09-300000003570us-gaap:ForeignExchangeContractMemberus-gaap:DerivativeFinancialInstrumentsLiabilitiesMember2019-12-310000003570us-gaap:ForeignExchangeContractMemberlng:NoncurrentDerivativeLiabilitiesMember2020-09-300000003570us-gaap:ForeignExchangeContractMemberlng:NoncurrentDerivativeLiabilitiesMember2019-12-310000003570us-gaap:ForeignExchangeContractMemberus-gaap:SalesMember2020-07-012020-09-300000003570us-gaap:ForeignExchangeContractMemberus-gaap:SalesMember2019-07-012019-09-300000003570us-gaap:ForeignExchangeContractMemberus-gaap:SalesMember2020-01-012020-09-300000003570us-gaap:ForeignExchangeContractMemberus-gaap:SalesMember2019-01-012019-09-300000003570lng:CCHInterestRateDerivativeLiabilityMember2020-09-300000003570lng:PriceRiskDerivativeAssetMember2020-09-300000003570lng:PriceRiskDerivativeLiabilityMember2020-09-300000003570lng:LNGTradingDerivativeAssetMember2020-09-300000003570lng:LNGTradingDerivativesLiabilityMember2020-09-300000003570lng:ForeignExchangeContractAssetMember2020-09-300000003570lng:ForeignExchangeContractLiabilityMember2020-09-300000003570lng:CCHInterestRateDerivativeLiabilityMember2019-12-310000003570lng:PriceRiskDerivativeAssetMember2019-12-310000003570lng:PriceRiskDerivativeLiabilityMember2019-12-310000003570lng:LNGTradingDerivativeAssetMember2019-12-310000003570lng:LNGTradingDerivativesLiabilityMember2019-12-310000003570lng:ForeignExchangeContractAssetMember2019-12-310000003570lng:ForeignExchangeContractLiabilityMember2019-12-310000003570lng:MidshipHoldingsLLCMember2020-01-012020-09-300000003570lng:MidshipHoldingsLLCMember2020-07-012020-09-300000003570lng:MidshipHoldingsLLCMember2020-09-300000003570lng:MidshipHoldingsLLCMember2019-12-310000003570lng:CommonUnitsMemberlng:CheniereEnergyPartnersLPMember2020-09-300000003570lng:CheniereEnergyPartnersLPMember2020-01-012020-09-300000003570lng:CheniereEnergyPartnersLPMember2019-12-310000003570lng:SabinePassLiquefactionMemberus-gaap:SeniorNotesMembersrt:MinimumMember2020-09-300000003570lng:SabinePassLiquefactionMemberus-gaap:SeniorNotesMembersrt:MaximumMember2020-09-300000003570lng:SabinePassLiquefactionMember2020-09-300000003570lng:SabinePassLiquefactionMember2019-12-310000003570lng:CheniereEnergyPartnersLPMemberus-gaap:SeniorNotesMembersrt:MinimumMember2020-09-300000003570lng:CheniereEnergyPartnersLPMemberus-gaap:SeniorNotesMembersrt:MaximumMember2020-09-300000003570us-gaap:SeniorNotesMemberlng:CheniereCorpusChristiHoldingsLLCMembersrt:MinimumMember2020-09-300000003570us-gaap:SeniorNotesMemberlng:CheniereCorpusChristiHoldingsLLCMembersrt:MaximumMember2020-09-300000003570lng:CheniereCorpusChristiHoldingsLLCMember2020-09-300000003570lng:CheniereCorpusChristiHoldingsLLCMember2019-12-310000003570lng:CheniereCCHHoldcoIILLCMemberlng:A2025ConvertibleSeniorNotesMember2020-09-300000003570lng:CheniereCCHHoldcoIILLCMember2020-09-300000003570lng:CheniereCCHHoldcoIILLCMember2019-12-310000003570srt:ParentCompanyMemberlng:A2028CheniereSeniorSecuredNotesMember2020-09-300000003570srt:ParentCompanyMember2020-09-300000003570srt:ParentCompanyMember2019-12-310000003570us-gaap:LongTermDebtMember2020-09-300000003570us-gaap:LongTermDebtMember2019-12-310000003570lng:SabinePassLiquefactionMemberlng:WorkingCapitalFacilityMember2020-09-300000003570lng:CorpusChristiHoldingsWorkingCapitalFacilityMemberlng:CheniereCorpusChristiHoldingsLLCMember2020-09-300000003570lng:A2021ConvertibleUnsecuredNotesMember2020-09-300000003570us-gaap:ShortTermDebtMember2020-09-300000003570us-gaap:ShortTermDebtMember2019-12-310000003570lng:SabinePassLiquefactionMemberlng:A2030SabinePassLiquefactionSeniorNotesMember2020-09-300000003570lng:SabinePassLiquefactionMemberlng:A2030SabinePassLiquefactionSeniorNotesMember2020-01-012020-09-300000003570lng:A2039352CorpusChristiHoldingsSeniorNotesMemberlng:CheniereCorpusChristiHoldingsLLCMember2020-09-300000003570lng:A2039352CorpusChristiHoldingsSeniorNotesMemberlng:CheniereCorpusChristiHoldingsLLCMember2020-01-012020-09-300000003570srt:ParentCompanyMemberlng:A2028CheniereSeniorSecuredNotesMember2020-01-012020-09-300000003570lng:A2039352CorpusChristiHoldingsSeniorNotesMemberlng:CheniereCorpusChristiHoldingsLLCMember2020-07-012020-09-300000003570lng:CheniereTermLoanFacilityMemberus-gaap:CashMember2020-01-012020-09-300000003570lng:CheniereTermLoanFacilityMember2020-01-012020-09-300000003570lng:CheniereTermLoanFacilityMember2020-09-300000003570lng:A2025ConvertibleSeniorNotesMember2020-09-300000003570lng:A2021ConvertibleUnsecuredNotesMember2020-07-012020-07-310000003570lng:A2025CCHHoldCoIIConvertibleNotesAnd2021CheniereConvertibleNotesMember2020-01-012020-09-300000003570lng:A2020SPLWorkingCapitalFacilityMember2020-09-300000003570lng:A2019CQPCreditFacilitiesMember2020-09-300000003570lng:A2015CCHTermLoanFacilityMember2020-09-300000003570lng:CorpusChristiHoldingsWorkingCapitalFacilityMember2020-09-300000003570lng:CheniereRevolvingCreditFacilityMember2020-09-30utr:Rate0000003570us-gaap:LondonInterbankOfferedRateLIBORMembersrt:MinimumMemberlng:A2020SPLWorkingCapitalFacilityMember2020-01-012020-09-300000003570us-gaap:LondonInterbankOfferedRateLIBORMembersrt:MaximumMemberlng:A2020SPLWorkingCapitalFacilityMember2020-01-012020-09-300000003570us-gaap:BaseRateMembersrt:MinimumMemberlng:A2020SPLWorkingCapitalFacilityMember2020-01-012020-09-300000003570us-gaap:BaseRateMembersrt:MaximumMemberlng:A2020SPLWorkingCapitalFacilityMember2020-01-012020-09-300000003570lng:A2019CQPCreditFacilitiesMemberus-gaap:LondonInterbankOfferedRateLIBORMembersrt:MinimumMember2020-01-012020-09-300000003570lng:A2019CQPCreditFacilitiesMemberus-gaap:LondonInterbankOfferedRateLIBORMembersrt:MaximumMember2020-01-012020-09-300000003570lng:A2019CQPCreditFacilitiesMemberus-gaap:BaseRateMembersrt:MinimumMember2020-01-012020-09-300000003570lng:A2019CQPCreditFacilitiesMemberus-gaap:BaseRateMembersrt:MaximumMember2020-01-012020-09-300000003570lng:A2015CCHTermLoanFacilityMemberus-gaap:LondonInterbankOfferedRateLIBORMember2020-01-012020-09-300000003570lng:A2015CCHTermLoanFacilityMemberus-gaap:BaseRateMember2020-01-012020-09-300000003570lng:CorpusChristiHoldingsWorkingCapitalFacilityMemberus-gaap:LondonInterbankOfferedRateLIBORMembersrt:MinimumMember2020-01-012020-09-300000003570lng:CorpusChristiHoldingsWorkingCapitalFacilityMemberus-gaap:LondonInterbankOfferedRateLIBORMembersrt:MaximumMember2020-01-012020-09-300000003570lng:CorpusChristiHoldingsWorkingCapitalFacilityMemberus-gaap:BaseRateMembersrt:MinimumMember2020-01-012020-09-300000003570lng:CorpusChristiHoldingsWorkingCapitalFacilityMemberus-gaap:BaseRateMembersrt:MaximumMember2020-01-012020-09-300000003570us-gaap:LondonInterbankOfferedRateLIBORMemberlng:CheniereRevolvingCreditFacilityMembersrt:MinimumMember2020-01-012020-09-300000003570us-gaap:LondonInterbankOfferedRateLIBORMemberlng:CheniereRevolvingCreditFacilityMembersrt:MaximumMember2020-01-012020-09-300000003570us-gaap:BaseRateMemberlng:CheniereRevolvingCreditFacilityMembersrt:MinimumMember2020-01-012020-09-300000003570us-gaap:BaseRateMemberlng:CheniereRevolvingCreditFacilityMembersrt:MaximumMember2020-01-012020-09-300000003570lng:A2020SPLWorkingCapitalFacilityMember2020-01-012020-09-300000003570lng:A2019CQPCreditFacilitiesMember2020-01-012020-09-300000003570lng:A2015CCHTermLoanFacilityMember2020-01-012020-09-300000003570lng:CorpusChristiHoldingsWorkingCapitalFacilityMember2020-01-012020-09-300000003570lng:CheniereRevolvingCreditFacilityMember2020-01-012020-09-300000003570srt:MinimumMemberlng:A2020SPLWorkingCapitalFacilityMember2020-01-012020-09-300000003570srt:MaximumMemberlng:A2020SPLWorkingCapitalFacilityMember2020-01-012020-09-300000003570lng:A2015CCHTermLoanFacilityMember2020-07-012020-09-300000003570lng:CheniereTermLoanFacilityMemberlng:FirstAnniversaryofClosingDateMember2020-01-012020-09-300000003570lng:SecondAnniversaryofClosingDateMemberlng:CheniereTermLoanFacilityMember2020-01-012020-09-300000003570us-gaap:LondonInterbankOfferedRateLIBORMemberlng:CheniereTermLoanFacilityMembersrt:MinimumMemberlng:Year1Member2020-01-012020-09-300000003570us-gaap:LondonInterbankOfferedRateLIBORMemberlng:CheniereTermLoanFacilityMembersrt:MaximumMemberlng:Year1Member2020-01-012020-09-300000003570us-gaap:LondonInterbankOfferedRateLIBORMemberlng:CheniereTermLoanFacilityMembersrt:MinimumMemberlng:Year2Member2020-01-012020-09-300000003570us-gaap:LondonInterbankOfferedRateLIBORMemberlng:CheniereTermLoanFacilityMembersrt:MaximumMemberlng:Year2Member2020-01-012020-09-300000003570us-gaap:LondonInterbankOfferedRateLIBORMemberlng:CheniereTermLoanFacilityMemberlng:Year3ThroughMaturityMembersrt:MinimumMember2020-01-012020-09-300000003570us-gaap:LondonInterbankOfferedRateLIBORMemberlng:CheniereTermLoanFacilityMemberlng:Year3ThroughMaturityMembersrt:MaximumMember2020-01-012020-09-300000003570us-gaap:BaseRateMemberlng:CheniereTermLoanFacilityMembersrt:MinimumMemberlng:Year1Member2020-01-012020-09-300000003570us-gaap:BaseRateMemberlng:CheniereTermLoanFacilityMembersrt:MaximumMemberlng:Year1Member2020-01-012020-09-300000003570us-gaap:BaseRateMemberlng:CheniereTermLoanFacilityMembersrt:MinimumMemberlng:Year2Member2020-01-012020-09-300000003570us-gaap:BaseRateMemberlng:CheniereTermLoanFacilityMembersrt:MaximumMemberlng:Year2Member2020-01-012020-09-300000003570us-gaap:BaseRateMemberlng:CheniereTermLoanFacilityMemberlng:Year3ThroughMaturityMembersrt:MinimumMember2020-01-012020-09-300000003570us-gaap:BaseRateMemberlng:CheniereTermLoanFacilityMemberlng:Year3ThroughMaturityMembersrt:MaximumMember2020-01-012020-09-300000003570lng:A2045ConvertibleSeniorNotesMember2020-09-300000003570lng:A2021ConvertibleUnsecuredNotesMember2020-01-012020-09-300000003570lng:A2045ConvertibleSeniorNotesMember2020-01-012020-09-300000003570us-gaap:ConvertibleDebtMember2020-07-012020-09-300000003570us-gaap:ConvertibleDebtMember2019-07-012019-09-300000003570us-gaap:ConvertibleDebtMember2020-01-012020-09-300000003570us-gaap:ConvertibleDebtMember2019-01-012019-09-300000003570lng:DebtExcludingCapitalLeaseAndConvertibleDebtMember2020-07-012020-09-300000003570lng:DebtExcludingCapitalLeaseAndConvertibleDebtMember2019-07-012019-09-300000003570lng:DebtExcludingCapitalLeaseAndConvertibleDebtMember2020-01-012020-09-300000003570lng:DebtExcludingCapitalLeaseAndConvertibleDebtMember2019-01-012019-09-300000003570us-gaap:SeniorNotesMemberus-gaap:CarryingReportedAmountFairValueDisclosureMemberus-gaap:FairValueInputsLevel2Member2020-09-300000003570us-gaap:SeniorNotesMemberus-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:FairValueInputsLevel2Member2020-09-300000003570us-gaap:SeniorNotesMemberus-gaap:CarryingReportedAmountFairValueDisclosureMemberus-gaap:FairValueInputsLevel2Member2019-12-310000003570us-gaap:SeniorNotesMemberus-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:FairValueInputsLevel2Member2019-12-310000003570us-gaap:SeniorNotesMemberus-gaap:FairValueInputsLevel3Memberus-gaap:CarryingReportedAmountFairValueDisclosureMember2020-09-300000003570us-gaap:SeniorNotesMemberus-gaap:FairValueInputsLevel3Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2020-09-300000003570us-gaap:SeniorNotesMemberus-gaap:FairValueInputsLevel3Memberus-gaap:CarryingReportedAmountFairValueDisclosureMember2019-12-310000003570us-gaap:SeniorNotesMemberus-gaap:FairValueInputsLevel3Memberus-gaap:EstimateOfFairValueFairValueDisclosureMember2019-12-310000003570us-gaap:CarryingReportedAmountFairValueDisclosureMemberus-gaap:LineOfCreditMember2020-09-300000003570us-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:LineOfCreditMember2020-09-300000003570us-gaap:CarryingReportedAmountFairValueDisclosureMemberus-gaap:LineOfCreditMember2019-12-310000003570us-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:LineOfCreditMember2019-12-310000003570us-gaap:CarryingReportedAmountFairValueDisclosureMemberlng:A2021ConvertibleUnsecuredNotesMember2020-09-300000003570lng:A2021ConvertibleUnsecuredNotesMemberus-gaap:EstimateOfFairValueFairValueDisclosureMember2020-09-300000003570us-gaap:CarryingReportedAmountFairValueDisclosureMemberlng:A2021ConvertibleUnsecuredNotesMember2019-12-310000003570lng:A2021ConvertibleUnsecuredNotesMemberus-gaap:EstimateOfFairValueFairValueDisclosureMember2019-12-310000003570lng:A2025ConvertibleSeniorNotesMemberus-gaap:CarryingReportedAmountFairValueDisclosureMember2020-09-300000003570lng:A2025ConvertibleSeniorNotesMemberus-gaap:EstimateOfFairValueFairValueDisclosureMember2020-09-300000003570lng:A2025ConvertibleSeniorNotesMemberus-gaap:CarryingReportedAmountFairValueDisclosureMember2019-12-310000003570lng:A2025ConvertibleSeniorNotesMemberus-gaap:EstimateOfFairValueFairValueDisclosureMember2019-12-310000003570us-gaap:CarryingReportedAmountFairValueDisclosureMemberlng:A2045ConvertibleSeniorNotesMember2020-09-300000003570us-gaap:EstimateOfFairValueFairValueDisclosureMemberlng:A2045ConvertibleSeniorNotesMember2020-09-300000003570us-gaap:CarryingReportedAmountFairValueDisclosureMemberlng:A2045ConvertibleSeniorNotesMember2019-12-310000003570us-gaap:EstimateOfFairValueFairValueDisclosureMemberlng:A2045ConvertibleSeniorNotesMember2019-12-310000003570lng:OperatingLeaseAssetsMember2020-09-300000003570lng:OperatingLeaseAssetsMember2019-12-310000003570us-gaap:PropertyPlantAndEquipmentMember2020-09-300000003570us-gaap:PropertyPlantAndEquipmentMember2019-12-310000003570lng:CurrentOperatingLeaseLiabilitiesMember2020-09-300000003570lng:CurrentOperatingLeaseLiabilitiesMember2019-12-310000003570us-gaap:OtherCurrentLiabilitiesMember2020-09-300000003570us-gaap:OtherCurrentLiabilitiesMember2019-12-310000003570lng:NonCurrentOperatingLeaseLiabilitiesMember2020-09-300000003570lng:NonCurrentOperatingLeaseLiabilitiesMember2019-12-310000003570us-gaap:OtherNoncurrentLiabilitiesMember2020-09-300000003570us-gaap:OtherNoncurrentLiabilitiesMember2019-12-310000003570us-gaap:OperatingExpenseMember2020-07-012020-09-300000003570us-gaap:OperatingExpenseMember2019-07-012019-09-300000003570us-gaap:OperatingExpenseMember2020-01-012020-09-300000003570us-gaap:OperatingExpenseMember2019-01-012019-09-300000003570lng:DepreciationandAmortizationExpenseMember2020-07-012020-09-300000003570lng:DepreciationandAmortizationExpenseMember2019-07-012019-09-300000003570lng:DepreciationandAmortizationExpenseMember2020-01-012020-09-300000003570lng:DepreciationandAmortizationExpenseMember2019-01-012019-09-300000003570us-gaap:InterestExpenseMember2020-07-012020-09-300000003570us-gaap:InterestExpenseMember2019-07-012019-09-300000003570us-gaap:InterestExpenseMember2020-01-012020-09-300000003570us-gaap:InterestExpenseMember2019-01-012019-09-300000003570srt:MaximumMember2020-09-300000003570lng:SuspensionFeesandLNGCoverDamagesRevenueMember2020-07-012020-09-300000003570lng:SuspensionFeesandLNGCoverDamagesRevenueMember2020-01-012020-09-300000003570lng:SuspensionFeesandLNGCoverDamagesRevenueMemberlng:SubsequentPeriodMember2020-07-012020-09-300000003570lng:SuspensionFeesandLNGCoverDamagesRevenueMemberlng:SubsequentPeriodMember2020-01-012020-09-300000003570lng:CurrentPeriodMemberlng:SuspensionFeesandLNGCoverDamagesRevenueMember2020-07-012020-09-3000000035702020-10-01lng:LiquefiedNaturalGasMember2020-09-300000003570lng:LiquefiedNaturalGasMember2020-01-012019-12-3100000035702020-10-01lng:RegasificationServiceMember2020-09-3000000035702020-01-01lng:RegasificationServiceMember2019-12-3100000035702020-10-012020-09-3000000035702020-01-012019-12-310000003570lng:SabinePassLiquefactionMemberlng:NaturalGasSupplyAgreementMember2020-01-012020-09-300000003570lng:SabinePassLiquefactionMemberlng:NaturalGasSupplyAgreementMember2020-09-300000003570lng:SabinePassLiquefactionMemberlng:NaturalGasSupplyAgreementMember2019-12-310000003570lng:NaturalGasSupplyAgreementMemberlng:CorpusChristiLiquefactionMember2020-09-300000003570lng:NaturalGasSupplyAgreementMemberlng:CorpusChristiLiquefactionMember2019-12-310000003570lng:NaturalGasSupplyAgreementMember2020-01-012020-09-300000003570lng:NaturalGasSupplyAgreementMemberus-gaap:PriceRiskDerivativeMemberlng:CorpusChristiLiquefactionMember2020-09-300000003570lng:NaturalGasSupplyAgreementMemberus-gaap:PriceRiskDerivativeMemberlng:CorpusChristiLiquefactionMember2019-12-310000003570lng:NaturalGasSupplyAgreementMemberlng:CorpusChristiLiquefactionMember2020-07-012020-09-300000003570lng:NaturalGasSupplyAgreementMemberlng:CorpusChristiLiquefactionMember2019-07-012019-09-300000003570lng:NaturalGasSupplyAgreementMemberlng:CorpusChristiLiquefactionMember2020-01-012020-09-300000003570lng:NaturalGasSupplyAgreementMemberlng:CorpusChristiLiquefactionMember2019-01-012019-09-300000003570lng:NaturalGasSupplyAgreementMemberus-gaap:PriceRiskDerivativeMemberlng:CorpusChristiLiquefactionMember2020-07-012020-09-300000003570lng:NaturalGasSupplyAgreementMemberus-gaap:PriceRiskDerivativeMemberlng:CorpusChristiLiquefactionMember2019-07-012019-09-300000003570lng:NaturalGasSupplyAgreementMemberus-gaap:PriceRiskDerivativeMemberlng:CorpusChristiLiquefactionMember2020-01-012020-09-300000003570lng:NaturalGasSupplyAgreementMemberus-gaap:PriceRiskDerivativeMemberlng:CorpusChristiLiquefactionMember2019-01-012019-09-300000003570lng:NaturalGasTransportationAndStorageAgreementsMemberlng:SabinePassLiquefactionLLCAndCheniereCreoleTrailPipelineLPMembersrt:MaximumMember2020-01-012020-09-300000003570lng:NaturalGasTransportationAndStorageAgreementsMemberlng:SabinePassLiquefactionLLCAndCheniereCreoleTrailPipelineLPMember2020-09-300000003570lng:NaturalGasTransportationAndStorageAgreementsMemberlng:SabinePassLiquefactionLLCAndCheniereCreoleTrailPipelineLPMember2019-12-310000003570us-gaap:ProductAndServiceOtherMemberlng:OperationAndMaintenanceAgreementMemberlng:CheniereLNGOMServicesLLCMember2019-07-012019-09-300000003570us-gaap:ProductAndServiceOtherMemberlng:OperationAndMaintenanceAgreementMemberlng:CheniereLNGOMServicesLLCMember2020-07-012020-09-300000003570us-gaap:ProductAndServiceOtherMemberlng:OperationAndMaintenanceAgreementMemberlng:CheniereLNGOMServicesLLCMember2020-01-012020-09-300000003570us-gaap:ProductAndServiceOtherMemberlng:OperationAndMaintenanceAgreementMemberlng:CheniereLNGOMServicesLLCMember2019-01-012019-09-300000003570lng:OperationAndMaintenanceAgreementMemberlng:CheniereLNGOMServicesLLCMember2020-09-300000003570lng:OperationAndMaintenanceAgreementMemberlng:CheniereLNGOMServicesLLCMember2019-12-310000003570us-gaap:RestrictedStockUnitsRSUMemberlng:A2011IncentivePlanAnd2020IncentivePlanMember2020-01-012020-09-300000003570us-gaap:PerformanceSharesMemberlng:A2011IncentivePlanAnd2020IncentivePlanMember2020-01-012020-09-300000003570us-gaap:CommonStockMemberlng:A2011IncentivePlanMember2020-01-012020-09-300000003570us-gaap:RestrictedStockUnitsRSUMember2020-01-012020-09-300000003570us-gaap:PerformanceSharesMember2020-01-012020-09-300000003570us-gaap:PerformanceSharesMembersrt:MinimumMember2020-01-012020-09-300000003570us-gaap:PerformanceSharesMembersrt:MaximumMember2020-01-012020-09-300000003570lng:EquityAwardsMember2020-07-012020-09-300000003570lng:EquityAwardsMember2019-07-012019-09-300000003570lng:EquityAwardsMember2020-01-012020-09-300000003570lng:EquityAwardsMember2019-01-012019-09-300000003570lng:LiabilityAwardsMember2020-07-012020-09-300000003570lng:LiabilityAwardsMember2019-07-012019-09-300000003570lng:LiabilityAwardsMember2020-01-012020-09-300000003570lng:LiabilityAwardsMember2019-01-012019-09-300000003570lng:UnvestedStockMember2020-07-012020-09-300000003570lng:UnvestedStockMember2019-07-012019-09-300000003570lng:UnvestedStockMember2020-01-012020-09-300000003570lng:UnvestedStockMember2019-01-012019-09-300000003570lng:A2021CheniereConvertibleNotesMember2020-07-012020-09-300000003570lng:A2021CheniereConvertibleNotesMember2019-07-012019-09-300000003570lng:A2021CheniereConvertibleNotesMember2020-01-012020-09-300000003570lng:A2021CheniereConvertibleNotesMember2019-01-012019-09-300000003570lng:A2025CCHHoldCoIIConvertibleNotesMember2020-07-012020-09-300000003570lng:A2025CCHHoldCoIIConvertibleNotesMember2019-07-012019-09-300000003570lng:A2025CCHHoldCoIIConvertibleNotesMember2020-01-012020-09-300000003570lng:A2025CCHHoldCoIIConvertibleNotesMember2019-01-012019-09-300000003570lng:A2045ConvertibleSeniorNotesMember2020-07-012020-09-300000003570lng:A2045ConvertibleSeniorNotesMember2019-07-012019-09-300000003570lng:A2045ConvertibleSeniorNotesMember2020-01-012020-09-300000003570lng:A2045ConvertibleSeniorNotesMember2019-01-012019-09-300000003570lng:RestrictedStockWithUnsatisfiedPerformanceConditionsMember2020-01-012020-09-300000003570lng:RestrictedStockWithUnsatisfiedPerformanceConditionsMember2020-07-012020-09-300000003570lng:RestrictedStockWithUnsatisfiedPerformanceConditionsMember2019-07-012019-09-300000003570lng:RestrictedStockWithUnsatisfiedPerformanceConditionsMember2019-01-012019-09-300000003570lng:CustomerAMemberus-gaap:SalesRevenueNetMember2019-07-012019-09-300000003570lng:CustomerAMemberus-gaap:SalesRevenueNetMember2020-01-012020-09-300000003570lng:CustomerAMemberus-gaap:SalesRevenueNetMember2019-01-012019-09-300000003570lng:CustomerAMemberlng:AccountsReceivableAndContractAssetsMember2019-01-012019-12-310000003570lng:CustomerBMemberus-gaap:SalesRevenueNetMember2020-07-012020-09-300000003570lng:CustomerBMemberus-gaap:SalesRevenueNetMember2019-07-012019-09-300000003570lng:CustomerBMemberus-gaap:SalesRevenueNetMember2020-01-012020-09-300000003570lng:CustomerBMemberus-gaap:SalesRevenueNetMember2019-01-012019-09-300000003570lng:CustomerCMemberus-gaap:SalesRevenueNetMember2020-07-012020-09-300000003570lng:CustomerCMemberus-gaap:SalesRevenueNetMember2019-07-012019-09-300000003570lng:CustomerCMemberus-gaap:SalesRevenueNetMember2020-01-012020-09-300000003570lng:CustomerCMemberus-gaap:SalesRevenueNetMember2019-01-012019-09-300000003570lng:AccountsReceivableAndContractAssetsMemberlng:CustomerCMember2019-01-012019-12-310000003570lng:CustomerDMemberus-gaap:SalesRevenueNetMember2020-07-012020-09-300000003570lng:CustomerDMemberus-gaap:SalesRevenueNetMember2019-07-012019-09-300000003570lng:CustomerDMemberus-gaap:SalesRevenueNetMember2020-01-012020-09-300000003570lng:CustomerDMemberus-gaap:SalesRevenueNetMember2019-01-012019-09-300000003570lng:CustomerDMemberlng:AccountsReceivableAndContractAssetsMember2020-01-012020-09-300000003570lng:AccountsReceivableAndContractAssetsMemberlng:CustomerEMember2020-01-012020-09-30


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020
or
☐    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to            
Commission file number 001-16383
LNG-20200930_G1.GIF
CHENIERE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware 95-4352386
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
700 Milam Street, Suite 1900
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 375-5000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: 
Title of each class Trading Symbol Name of each exchange on which registered
Common Stock, $ 0.003 par value LNG NYSE American
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒   No  ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes  ☒   No  ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☒ Accelerated filer ☐
Non-accelerated filer ☐ Smaller reporting company ☐
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  ☐  No  ☒ 
As of October 30, 2020, the issuer had 252,274,015 shares of Common Stock outstanding.


CHENIERE ENERGY, INC.
TABLE OF CONTENTS

1
3
3
4
5
7
8
30
 
54
 
55
56
56
 
56
57
58

i

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

Common Industry and Other Terms
Bcf billion cubic feet
Bcf/d billion cubic feet per day
Bcf/yr billion cubic feet per year
Bcfe billion cubic feet equivalent
DOE U.S. Department of Energy
EPC engineering, procurement and construction
FERC Federal Energy Regulatory Commission
FTA countries countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP generally accepted accounting principles in the United States
Henry Hub the final settlement price (in USD 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
LIBOR London Interbank Offered Rate
LNG liquefied 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
MMBtu million British thermal units, an energy unit
mtpa million tonnes per annum
non-FTA countries countries 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
SEC U.S. Securities and Exchange Commission
SPA LNG sale and purchase agreement
TBtu trillion British thermal units, an energy unit
Train an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA terminal use agreement

1

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of September 30, 2020, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:
LNG-20200930_G2.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, Cheniere Partners.
Unless the context requires otherwise, references to the “CCH Group” refer to CCH HoldCo II, CCH HoldCo I, CCH, CCL and CCP, collectively.

2

PART I.    FINANCIAL INFORMATION 
ITEM 1.    CONSOLIDATED FINANCIAL STATEMENTS
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (1)
(in millions, except share data)


September 30, December 31,
2020 2019
ASSETS (unaudited)  
Current assets    
Cash and cash equivalents $ 2,091  $ 2,474 
Restricted cash 522  520 
Accounts and other receivables, net 390  491 
Inventory 280  312 
Derivative assets 195  323 
Other current assets 154  92 
Total current assets 3,632  4,212 
Property, plant and equipment, net 30,201  29,673 
Operating lease assets, net 630  439 
Non-current derivative assets 592  174 
Goodwill 77  77 
Deferred tax assets 414  529 
Other non-current assets, net 385  388 
Total assets $ 35,931  $ 35,492 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities    
Accounts payable $ 41  $ 66 
Accrued liabilities 1,006  1,281 
Current debt 338  — 
Deferred revenue 179  161 
Current operating lease liabilities 160  236 
Derivative liabilities 164  117 
Other current liabilities 29  13 
Total current liabilities 1,917  1,874 
Long-term debt, net 30,949  30,774 
Non-current operating lease liabilities 473  189 
Non-current finance lease liabilities 58  58 
Non-current derivative liabilities 173  151 
Other non-current liabilities 14  11 
Commitments and contingencies (see Note 18)
Stockholders’ equity    
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued
—  — 
Common stock, $0.003 par value, 480.0 million shares authorized
Issued: 273.0 million shares at September 30, 2020 and 270.7 million shares at December 31, 2019
Outstanding: 252.2 million shares at September 30, 2020 and 253.6 million shares at December 31, 2019
1  1 
Treasury stock: 20.8 million shares and 17.1 million shares at September 30, 2020 and December 31, 2019, respectively, at cost
(872) (674)
Additional paid-in-capital 4,246  4,167 
Accumulated deficit (3,399) (3,508)
Total stockholders' deficit (24) (14)
Non-controlling interest 2,371  2,449 
Total equity 2,347  2,435 
Total liabilities and stockholders’ equity $ 35,931  $ 35,492 
(1)     Amounts presented include balances held by our consolidated variable interest entity (“VIE”), Cheniere Partners, as further discussed in Note 8— Non-controlling Interest and Variable Interest Entity. As of September 30, 2020, total assets and liabilities of Cheniere Partners, which are included in our Consolidated Balance Sheets, were $18.8 billion and $18.5 billion, respectively, including $1.3 billion of cash and cash equivalents and $0.2 billion of restricted cash.
The accompanying notes are an integral part of these consolidated financial statements.

3


CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
(unaudited)
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Revenues
LNG revenues $ 1,373  $ 2,059  $ 6,236  $ 6,375 
Regasification revenues 67  66  202  199 
Other revenues 20  45  133  149 
Total revenues 1,460  2,170  6,571  6,723 
Operating costs and expenses
Cost of sales (excluding items shown separately below) 768  1,267  2,295  3,758 
Operating and maintenance expense 317  308  988  824 
Development expense —  2  5  6 
Selling, general and administrative expense 70  72  224  222 
Depreciation and amortization expense 233  213  699  561 
Impairment expense and loss on disposal of assets —  1  5  7 
Total operating costs and expenses 1,388  1,863  4,216  5,378 
Income from operations 72  307  2,355  1,345 
Other expense
Interest expense, net of capitalized interest (355) (395) (1,174) (1,014)
Loss on modification or extinguishment of debt (171) (27) (215) (27)
Interest rate derivative loss, net —  (78) (233) (187)
Other expense, net (129) (70) (115) (38)
Total other expense (655) (570) (1,737) (1,266)
Income (loss) before income taxes and non-controlling interest (583) (263) 618  79 
Income tax benefit (provision) 75  3  (119) — 
Net income (loss) (508) (260) 499  79 
Less: net income (loss) attributable to non-controlling interest (45) 58  390  370 
Net income (loss) attributable to common stockholders $ (463) $ (318) $ 109  $ (291)
Net income (loss) per share attributable to common stockholders—basic and diluted (1) $ (1.84) $ (1.25) $ 0.43  $ (1.13)
Weighted average number of common shares outstanding—basic 252.2  256.0  252.5  256.8 
Weighted average number of common shares outstanding—diluted 252.2  256.0  253.2  256.8 
(1)     Earnings per share in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

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

4


CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in millions)
(unaudited)
Three and Nine Months Ended September 30, 2020
Total Stockholders’ Equity
  Common Stock Treasury Stock Additional Paid-in Capital Accumulated Deficit Non-controlling Interest Total
Equity
  Shares Par Value Amount Shares Amount
Balance at December 31, 2019 253.6  $ 1  17.1  $ (674) $ 4,167  $ (3,508) $ 2,449  $ 2,435 
Vesting of restricted stock units and performance stock units 2.1  —  —  —  —  —  —  — 
Share-based compensation —  —  —  —  29  —  —  29 
Issued shares withheld from employees related to share-based compensation, at cost (0.7) —  0.7  (39) —  —  —  (39)
Shares repurchased, at cost (2.9) —  2.9  (155) —  —  —  (155)
Net income attributable to non-controlling interest —  —  —  —  —  —  228  228 
Distributions and dividends to non-controlling interest —  —  —  —  —  —  (154) (154)
Net income —  —  —  —  —  375  —  375 
Balance at March 31, 2020 252.1  1  20.7  (868) 4,196  (3,133) 2,523  2,719 
Vesting of restricted stock units and performance stock units 0.1  —  —  —  —  —  —  — 
Share-based compensation —  —  —  —  31  —  —  31 
Issued shares withheld from employees related to share-based compensation, at cost —  —  —  (2) —  —  —  (2)
Net income attributable to non-controlling interest —  —  —  —  —  —  207  207 
Distributions and dividends to non-controlling interest —  —  —  —  —  —  (156) (156)
Net income —  —  —  —  —  197  —  197 
Balance at June 30, 2020 252.2  1  20.7  (870) 4,227  (2,936) 2,574  2,996 
Vesting of restricted stock units and performance stock units 0.1  —  —  —  —  —  —  — 
Share-based compensation —  —  —  —  26  —  —  26 
Issued shares withheld from employees related to share-based compensation, at cost (0.1) —  0.1  (2) —  —  —  (2)
Net loss attributable to non-controlling interest —  —  —  —  —  —  (45) (45)
Reacquisition of equity component of convertible notes, net of tax —  —  —  —  (7) —  —  (7)
Distributions and dividends to non-controlling interest —  —  —  —  —  —  (158) (158)
Net loss —  —  —  —  —  (463) —  (463)
Balance at September 30, 2020 252.2  $ 1  20.8  $ (872) $ 4,246  $ (3,399) $ 2,371  $ 2,347 
    
The accompanying notes are an integral part of these consolidated financial statements.

5


CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY—CONTINUED
(in millions)
(unaudited)
Three and Nine Months Ended September 30, 2019
Total Stockholders’ Equity
  Common Stock Treasury Stock Additional Paid-in Capital Accumulated Deficit Non-controlling Interest Total
Equity
  Shares Par Value Amount Shares Amount
Balance at December 31, 2018 257.0  $ 1  12.8  $ (406) $ 4,035  $ (4,156) $ 2,455  $ 1,929 
Vesting of restricted stock units 0.6  —  —  —  —  —  —  — 
Share-based compensation —  —  —  —  28  —  —  28 
Issued shares withheld from employees related to share-based compensation, at cost (0.2) —  0.2  (12) —  —  —  (12)
Net income attributable to non-controlling interest —  —  —  —  —  —  196  196 
Distributions and dividends to non-controlling interest —  —  —  —  —  —  (144) (144)
Net income —  —  —  —  —  141  —  141 
Balance at March 31, 2019 257.4  1  13.0  (418) 4,063  (4,015) 2,507  2,138 
Vesting of restricted stock units 0.1  —  —  —  —  —  —  — 
Share-based compensation —  —  —  —  33  —  —  33 
Issued shares withheld from employees related to share-based compensation, at cost —  —  —  (2) —  —  —  (2)
Shares repurchased, at cost —  —  —  (3) —  —  —  (3)
Net income attributable to non-controlling interest —  —  —  —  —  —  116  116 
Equity portion of convertible notes, net —  —  —  —  1  —  —  1 
Distributions and dividends to non-controlling interest —  —  —  —  —  —  (146) (146)
Net loss —  —  —  —  —  (114) —  (114)
Balance at June 30, 2019 257.5  1  13.0  (423) 4,097  (4,129) 2,477  2,023 
Vesting of restricted stock units 0.1  —  —  —  —  —  —  — 
Share-based compensation —  —  —  —  33  —  —  33 
Issued shares withheld from employees related to share-based compensation, at cost (0.1) —  0.1  (5) —  —  —  (5)
Shares repurchased, at cost (2.5) —  2.5  (156) —  —  —  (156)
Net income attributable to non-controlling interest —  —  —  —  —  —  58  58 
Distributions and dividends to non-controlling interest —  —  —  —  —  —  (149) (149)
Net loss —  —  —  —  —  (318) —  (318)
Balance at September 30, 2019 255.0  $ 1  15.6  $ (584) $ 4,130  $ (4,447) $ 2,386  $ 1,486 

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

6


CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
(unaudited)
Nine Months Ended September 30,
2020 2019
Cash flows from operating activities
Net income $ 499  $ 79 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense 699  561 
Share-based compensation expense 84  94 
Non-cash interest expense 43  122 
Amortization of debt issuance costs, premium and discount 94  71 
Non-cash operating lease costs 222  251 
Loss on modification or extinguishment of debt 215  27 
Total losses (gains) on derivatives, net (282) 22 
Net cash provided by settlement of derivative instruments 61  108 
Impairment expense and loss on disposal of assets 5  7 
Impairment or loss on equity method investments 130  88 
Deferred taxes 115  (2)
Repayment of paid-in-kind interest related to repurchase of convertible notes (911) — 
Other 2  — 
Changes in operating assets and liabilities:
Accounts and other receivables, net 101  (5)
Inventory 31  35 
Other current assets (27) (45)
Accounts payable and accrued liabilities (93) (82)
Deferred revenue 18  33 
Operating lease liabilities (205) (263)
Finance lease liabilities —  1 
Other, net (36) (10)
Net cash provided by operating activities 765  1,092 
Cash flows from investing activities
Property, plant and equipment, net (1,437) (2,587)
Investment in equity method investment (100) (70)
Other (8) (1)
Net cash used in investing activities (1,545) (2,658)
Cash flows from financing activities
Proceeds from issuances of debt 7,683  4,420 
Repayments of debt (6,324) (2,237)
Debt issuance and other financing costs (124) (38)
Debt modification or extinguishment costs (170) (4)
Distributions and dividends to non-controlling interest (468) (439)
Payments related to tax withholdings for share-based compensation (43) (19)
Repurchase of common stock (155) (159)
Other —  3 
Net cash provided by financing activities 399  1,527 
Net decrease in cash, cash equivalents and restricted cash (381) (39)
Cash, cash equivalents and restricted cash—beginning of period 2,994  3,156 
Cash, cash equivalents and restricted cash—end of period $ 2,613  $ 3,117 
Balances per Consolidated Balance Sheet:
September 30,
2020
Cash and cash equivalents $ 2,091 
Restricted cash 522 
Total cash, cash equivalents and restricted cash $ 2,613 
The accompanying notes are an integral part of these consolidated financial statements.

7

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

We are operating and constructing two natural gas liquefaction and export facilities at Sabine Pass and Corpus Christi. The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners, through its subsidiary SPL, is currently operating five natural gas liquefaction Trains and is constructing one additional Train for a total production capacity of approximately 30 mtpa of LNG (the “SPL Project”) at the Sabine Pass LNG terminal. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ subsidiary, SPLNG, that include pre-existing infrastructure of five LNG storage tanks, two marine berths and vaporizers and an additional marine berth that is under construction. Cheniere Partners also owns a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through its subsidiary, CTPL. As of September 30, 2020, we owned 100% of the general partner interest and 48.6% of the limited partner interest in Cheniere Partners.

The Corpus Christi LNG terminal is located near Corpus Christi, Texas and is operated and constructed by our subsidiary, CCL. We are currently operating two Trains and one additional Train is undergoing commissioning for a total production capacity of approximately 15 mtpa of LNG. We also operate a 23-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, the “CCL Project”) through our subsidiary, CCP. The CCL Project, once fully constructed, will contain three LNG storage tanks and two marine berths.

Additionally, separate from the CCH Group, we are developing an expansion of the Corpus Christi LNG terminal adjacent to the CCL Project (“Corpus Christi Stage 3”) through our subsidiary CCL Stage III, for up to seven midscale Trains with an expected total production capacity of approximately 10 mtpa of LNG. We received approval from FERC in November 2019 to site, construct and operate the expansion project.

We remain focused on operational excellence and customer satisfaction. Increasing demand of LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. 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. 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 final investment decision (“FID”).

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere have been prepared in accordance with GAAP for interim financial information and with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2019.

Results of operations for the three and nine months ended September 30, 2020 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2020.

Recent Accounting Standards

In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. This guidance simplifies the accounting for convertible instruments primarily by eliminating the existing cash conversion and beneficial conversion models within Subtopic 470-20, which will result in fewer embedded conversion options being accounted for separately from the debt host. The guidance also amends and simplifies the calculation of earnings per share relating to convertible instruments. This guidance is effective for annual periods beginning after December 15, 2021, including interim periods within that reporting period, with earlier adoption permitted for fiscal years beginning after December 15, 2020,
8

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
including interim periods within that reporting period, using either a full or modified retrospective approach. We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.

NOTE 2—RESTRICTED CASH
 
Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of September 30, 2020 and December 31, 2019, restricted cash consisted of the following (in millions):
September 30, December 31,
2020 2019
Current restricted cash
SPL Project $ 157  $ 181 
CCL Project 145  80 
Cash held by our subsidiaries restricted to Cheniere 220  259 
Total current restricted cash $ 522  $ 520 
Pursuant to the accounts agreements entered into with the collateral trustees for the benefit of SPL’s debt holders and CCH’s debt holders, SPL and CCH are required to deposit all cash received into reserve accounts controlled by the collateral trustees.  The usage or withdrawal of such cash is restricted to the payment of liabilities related to the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) and other restricted payments. The majority of the cash held by our subsidiaries restricted to Cheniere relates to advance funding for operation and construction needs of the Liquefaction Projects.

NOTE 3—ACCOUNTS AND OTHER RECEIVABLES

As of September 30, 2020 and December 31, 2019, accounts and other receivables, net consisted of the following (in millions):
September 30, December 31,
2020 2019
Trade receivables
SPL and CCL $ 249  $ 328 
Cheniere Marketing 41  113 
Other accounts receivable 100  50 
Total accounts and other receivables, net $ 390  $ 491 

9

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 4—INVENTORY

As of September 30, 2020 and December 31, 2019, inventory consisted of the following (in millions):
September 30, December 31,
2020 2019
Natural gas $ 21  $ 16 
LNG 45  67 
LNG in-transit 69  93 
Materials and other 145  136 
Total inventory $ 280  $ 312 

NOTE 5—PROPERTY, PLANT AND EQUIPMENT
 
As of September 30, 2020 and December 31, 2019, property, plant and equipment, net consisted of the following (in millions):
September 30, December 31,
2020 2019
LNG terminal costs    
LNG terminal and interconnecting pipeline facilities $ 27,435  $ 27,305 
LNG site and related costs 324  322 
LNG terminal construction-in-process 4,977  3,903 
Accumulated depreciation (2,716) (2,049)
Total LNG terminal costs, net 30,020  29,481 
Fixed assets and other    
Computer and office equipment 25  23 
Furniture and fixtures 19  22 
Computer software 115  110 
Leasehold improvements 47  42 
Land 59  59 
Other 24  21 
Accumulated depreciation (162) (141)
Total fixed assets and other, net 127  136 
Assets under finance lease
Tug vessels 60  60 
Accumulated depreciation (6) (4)
Total assets under finance lease, net 54  56 
Property, plant and equipment, net $ 30,201  $ 29,673 

The following table shows depreciation expense and offsets to LNG terminal costs during the three and nine months ended September 30, 2020 and 2019 (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Depreciation expense $ 231  $ 211  $ 694  $ 557 
Offsets to LNG terminal costs (1) —  99 —  301
(1)    We realize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Projects during the testing phase for its construction.

10

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 6—DERIVATIVE INSTRUMENTS
 
We have entered into the following derivative instruments that are reported at fair value:
•interest rate swaps (“CCH Interest Rate Derivatives”) to hedge the exposure to volatility in a portion of the floating-rate interest payments on CCH’s amended and restated credit facility (the “CCH Credit Facility”) and to hedge against changes in interest rates that could impact anticipated future issuance of debt by CCH (“CCH Interest Rate Forward Start Derivatives” and, collectively with the CCH Interest Rate Derivatives, the “Interest Rate Derivatives”);
•commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Projects and potential future development of Corpus Christi Stage 3 (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”);
•financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (“LNG Trading Derivatives”); and
•foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with both LNG Trading Derivatives and operations in countries outside of the United States (“FX Derivatives”).
We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process.
The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of September 30, 2020 and December 31, 2019, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions):
Fair Value Measurements as of
September 30, 2020 December 31, 2019
Quoted Prices in Active Markets
(Level 1) 		Significant Other Observable Inputs
(Level 2) 		Significant Unobservable Inputs
(Level 3) 		Total Quoted Prices in Active Markets
(Level 1) 		Significant Other Observable Inputs
(Level 2) 		Significant Unobservable Inputs
(Level 3) 		Total
CCH Interest Rate Derivatives liability $ —  $ (165) $ —  $ (165) $ —  $ (81) $ —  $ (81)
CCH Interest Rate Forward Start Derivatives liability —  —  —  —  —  (8) —  (8)
Liquefaction Supply Derivatives asset (liability) (7) (5) 533  521  5  6  138  149 
LNG Trading Derivatives asset 12  80  —  92  —  165  —  165 
FX Derivatives asset —  2  —  2  —  4  —  4 

We value our Interest Rate Derivatives using an income-based approach utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our LNG Trading Derivatives and our Liquefaction Supply Derivatives using a market or option-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data. We value our FX Derivatives with a market approach using observable FX rates and other relevant data.

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of September 30, 2020 and December 31, 2019, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.
11

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration.

The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2020:
Net Fair Value Asset
(in millions) 		Valuation Approach Significant Unobservable Input Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives $533 Market approach incorporating present value techniques Henry Hub basis spread
$(0.557) - $0.055 / $(0.030)
Option pricing model International LNG pricing spread, relative to Henry Hub (2)
56% - 173% / 137%
(1)Unobservable inputs were weighted by the relative fair value of the instruments.
(2)Spread contemplates U.S. dollar-denominated pricing.

Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and nine months ended September 30, 2020 and 2019 (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Balance, beginning of period $ 590  $ 89  $ 138  $ (29)
Realized and mark-to-market gains (losses):
Included in cost of sales (27) (137) 454  (139)
Purchases and settlements:
Purchases 1  17  2  93 
Settlements (31) —  (61) 44 
Balance, end of period $ 533  $ (31) $ 533  $ (31)
Change in unrealized gains (losses) relating to instruments still held at end of period $ (27) $ (137) $ 454  $ (139)

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for the unconditional right of set-off in the event of default. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

12

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
Interest Rate Derivatives

In August 2020, we settled the outstanding CCH Interest Rate Forward Start Derivatives used to hedge against changes in the interest rates of CCH’s debt.

As of September 30, 2020, we had the following Interest Rate Derivatives outstanding:
Notional Amounts
September 30, 2020 December 31, 2019 Maturity Date Weighted Average Fixed Interest Rate Paid Variable Interest Rate Received
CCH Interest Rate Derivatives $4.7 billion $4.5 billion May 31, 2022 2.30% One-month LIBOR

The following table shows the fair value and location of the Interest Rate Derivatives on our Consolidated Balance Sheets (in millions):
September 30, 2020 December 31, 2019
CCH Interest Rate Derivatives CCH Interest Rate Forward Start Derivatives Total CCH Interest Rate Derivatives CCH Interest Rate Forward Start Derivatives Total
Consolidated Balance Sheets Location
Derivative liabilities $ (99) $ —  $ (99) $ (32) $ (8) $ (40)
Non-current derivative liabilities (66) —  (66) (49) —  (49)
Total derivative liabilities $ (165) $ —  $ (165) $ (81) $ (8) $ (89)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in interest rate derivative loss, net on our Consolidated Statements of Operations during the three and nine months ended September 30, 2020 and 2019 (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
CCH Interest Rate Derivatives loss $ —  $ (17) $ (138) $ (119)
CCH Interest Rate Forward Start Derivatives loss —  (61) (95) (68)

Commodity Derivatives

SPL, CCL and CCL Stage III have entered into physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Projects and potential future development of Corpus Christi Stage 3, respectively, which are primarily indexed to the natural gas market and international LNG indices. The remaining terms of the index-based physical natural gas supply contracts range up to approximately 15 years, some of which commence upon the satisfaction of certain events or states of affairs.

We have entered into, and may from time to time enter into, financial LNG Trading Derivatives in the form of swaps, forwards, options or futures to economically hedge exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG. We have entered into LNG Trading Derivatives to secure a fixed price position to minimize future cash flow variability associated with LNG purchase and sale transactions.

13

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
The following table shows the fair value and location of our Liquefaction Supply Derivatives and LNG Trading Derivatives (collectively, “Commodity Derivatives”) on our Consolidated Balance Sheets (in millions, except notional amount):
September 30, 2020 December 31, 2019
Liquefaction Supply Derivatives (1) LNG Trading Derivatives (2) Total Liquefaction Supply Derivatives (1) LNG Trading Derivatives (2) Total
Consolidated Balance Sheets Location
Derivative assets $ 96  $ 91  $ 187  $ 93  $ 225  $ 318 
Non-current derivative assets 584  8  592  174  —  174 
Total derivative assets 680  99  779  267  225  492 
Derivative liabilities (53) (7) (60) (16) (60) (76)
Non-current derivative liabilities (106) —  (106) (102) —  (102)
Total derivative liabilities (159) (7) (166) (118) (60) (178)
Derivative asset, net $ 521  $ 92  $ 613  $ 149  $ 165  $ 314 
Notional amount, net (in TBtu) (3) 8,818  4  9,177  4 
(1)    Does not include collateral posted with counterparties by us of $20 million and $7 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019, respectively. Includes derivative assets for natural gas supply contracts that SPL and CCL have with related parties. See Note 13—Related Party Transactions.
(2)    Does not include collateral posted with counterparties by us of zero and $5 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019, respectively.
(3)    Includes notional amounts for natural gas supply contracts that SPL and CCL have with related parties. See Note 13—Related Party Transactions.

The following table shows the changes in the fair value, settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2020 and 2019 (in millions):
Consolidated Statements of Operations Location (1) Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
LNG Trading Derivatives gain LNG revenues $ 13  $ 22  $ 119  $ 180 
LNG Trading Derivatives loss Cost of sales (5) (17) (5) (68)
Liquefaction Supply Derivatives gain (2) LNG revenues 21  —  7  1 
Liquefaction Supply Derivatives gain (loss) (2) Cost of sales (103) (139) 372  — 
(1)    Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
(2)    Does not include the realized value associated with derivative instruments that settle through physical delivery.

FX Derivatives

Cheniere Marketing has entered into FX Derivatives to protect against the volatility in future cash flows attributable to changes in international currency exchange rates. The FX Derivatives economically hedge the foreign currency exposure arising from cash flows expended for both physical and financial LNG transactions.

14

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
The following table shows the fair value and location of our FX Derivatives on our Consolidated Balance Sheets (in millions):
Fair Value Measurements as of
Consolidated Balance Sheets Location September 30, 2020 December 31, 2019
FX Derivatives Derivative assets $ 8  $ 5 
FX Derivatives Derivative liabilities (5) (1)
FX Derivatives Non-current derivative liabilities (1) — 

The total notional amount of our FX Derivatives was $535 million and $827 million as of September 30, 2020 and December 31, 2019, respectively.
    
The following table shows the changes in the fair value, settlements and location of our FX Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2020 and 2019 (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
Consolidated Statements of Operations Location 2020 2019 2020 2019
FX Derivatives gain (loss) LNG revenues $ (5) $ 43  $ 22  $ 52 

Consolidated Balance Sheets Presentation

Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):
Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of September 30, 2020
CCH Interest Rate Derivatives $ (165) $ —  $ (165)
Liquefaction Supply Derivatives 687  (7) 680 
Liquefaction Supply Derivatives (177) 18  (159)
LNG Trading Derivatives 111  (12) 99 
LNG Trading Derivatives (14) 7  (7)
FX Derivatives 17  (9) 8 
FX Derivatives (21) 15  (6)
As of December 31, 2019
CCH Interest Rate Derivatives $ (81) $ —  $ (81)
CCH Interest Rate Forward Start Derivatives (8) —  (8)
Liquefaction Supply Derivatives 281  (14) 267 
Liquefaction Supply Derivatives (126) 8  (118)
LNG Trading Derivatives 229  (4) 225 
LNG Trading Derivatives (60) —  (60)
FX Derivatives 9  (4) 5 
FX Derivatives (6) 5  (1)

15

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 7—OTHER NON-CURRENT ASSETS

As of September 30, 2020 and December 31, 2019, other non-current assets, net consisted of the following (in millions):
September 30, December 31,
2020 2019
Advances made to municipalities for water system enhancements $ 85  $ 87 
Advances and other asset conveyances to third parties to support LNG terminals 61  55 
Advances made under EPC and non-EPC contracts 5  29 
Equity method investments 77  108 
Debt issuance costs and debt discount, net 46  45 
Tax-related payments and receivables 20  20 
Contract assets, net 64  18 
Other 27  26 
Total other non-current assets, net $ 385  $ 388 
Equity Method Investments

Our equity method investments consist of interests in privately-held companies. In 2017, we acquired an equity interest in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline Company, LLC (“Midship Pipeline”), which we account for as an equity method investment. See Note 8—Other Non-Current Assets of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the fiscal year ended December 31, 2019 for further information.

During the three and nine months ended September 30, 2020, we recognized other-than-temporary impairment losses of $129 million related to our investment in Midship Holdings. Impairment was precipitated primarily due to declining market conditions in the energy industry and customer credit risk, resulting in a reduction in the fair value of our equity interests. During the three and nine months ended September 30, 2019, we recognized losses of $87 million related to our investments in certain equity method investees, including Midship Holdings. Impairments were primarily the result of cost overruns and extended construction timelines for operating infrastructure of our investees’ projects, resulting in a reduction of the fair value of our equity interests. The fair values of our equity interests were measured using an income approach, which utilized level 3 fair value inputs such as projected earnings and discount rates, and/or market approach. Impairment losses associated with our equity method investments are presented in other expense, net.

Our investment in Midship Holdings, net of impairment losses, was $76 million and $105 million at September 30, 2020 and December 31, 2019, respectively.

NOTE 8—NON-CONTROLLING INTEREST AND VARIABLE INTEREST ENTITY

We own a 48.6% limited partner interest in Cheniere Partners in the form of 239.9 million common units, with the remaining non-controlling interest held by The Blackstone Group Inc., Brookfield Asset Management Inc. and the public. In July 2020, the board of directors of Cheniere Partners’ general partner confirmed and approved that, following the distribution with respect to the three months ended June 30, 2020, the financial tests required for conversion of Cheniere Partners’ subordinated units, all of which were held by us, were met under the terms of Cheniere Partners’ partnership agreement. Accordingly, effective August 17, 2020, the first business day following the payment of the distribution, all of Cheniere Partners’ subordinated units were automatically converted into common units on a one-for-one basis and the subordination period was terminated. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners. Cheniere Partners is accounted for as a consolidated VIE. See Note 9—Non-Controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the fiscal year ended December 31, 2019 for further information.
16

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

The following table presents the summarized assets and liabilities (in millions) of Cheniere Partners, our consolidated VIE, which are included in our Consolidated Balance Sheets. The assets in the table below may only be used to settle obligations of Cheniere Partners. In addition, there is no recourse to us for the consolidated VIE’s liabilities. The assets and liabilities in the table below include third-party assets and liabilities of Cheniere Partners only and exclude intercompany balances that eliminate in consolidation.
September 30, December 31,
2020 2019
ASSETS  
Current assets    
Cash and cash equivalents $ 1,254  $ 1,781 
Restricted cash 157  181 
Accounts and other receivables, net 204  297 
Other current assets 244  184 
Total current assets 1,859  2,443 
Property, plant and equipment, net 16,666  16,368 
Other non-current assets, net 303  309 
Total assets $ 18,828  $ 19,120 
LIABILITIES    
Current liabilities    
Accrued liabilities $ 564  $ 709 
Other current liabilities 236  210 
Total current liabilities 800  919 
Long-term debt, net 17,573  17,579 
Other non-current liabilities 119  104 
Total liabilities $ 18,492  $ 18,602 

NOTE 9—ACCRUED LIABILITIES
  
As of September 30, 2020 and December 31, 2019, accrued liabilities consisted of the following (in millions): 
September 30, December 31,
2020 2019
Interest costs and related debt fees $ 375  $ 293 
Accrued natural gas purchases 350  460 
LNG terminals and related pipeline costs 106  327 
Compensation and benefits 88  115 
Accrued LNG inventory 3  6 
Other accrued liabilities 84  80 
Total accrued liabilities $ 1,006  $ 1,281 
 
17

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 10—DEBT
 
As of September 30, 2020 and December 31, 2019, our debt consisted of the following (in millions): 
September 30, December 31,
2020 2019
Long-term debt:
SPL — 4.200% to 6.25% senior secured notes due through 2037 and working capital facility (“2020 SPL Working Capital Facility”)
$ 13,650  $ 13,650 
Cheniere Partners — 4.500% to 5.625% senior notes due through 2029 and credit facilities (“2019 CQP Credit Facilities”)
4,100  4,100 
CCH — 3.52% to 7.000% senior secured notes due through 2039 and CCH Credit Facility
10,240  10,235 
CCH HoldCo II —11.0% Convertible Senior Secured Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)
—  1,578 
Cheniere — 4.625% Senior Secured Notes due 2028 (the “2028 Cheniere Senior Secured Notes”), convertible notes, revolving credit facility (“Cheniere Revolving Credit Facility”) and term loan facility (“Cheniere Term Loan Facility”)
3,620  1,903 
Unamortized premium, discount and debt issuance costs, net (661) (692)
Total long-term debt, net 30,949  30,774 
Current debt:
SPL — $1.2 billion Amended and Restated SPL Working Capital Facility (“2015 SPL Working Capital Facility”)
—  — 
CCH — $1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) and current portion of CCH Credit Facility
249  — 
Cheniere Marketing — trade finance facilities
—  — 
Cheniere — current portion of 4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”)
93 — 
Unamortized premium, discount and debt issuance costs, net (4) — 
Total current debt 338  — 
Total debt, net $ 31,287  $ 30,774 

Issuances

The following table shows the issuances of debt during the nine months ended September 30, 2020:
Maturity Date Interest Rate Principal Amount Issued (in millions)
Three Months Ended June 30, 2020
SPL — 4.500% Senior Secured Notes due 2030 (the “2030 SPL Senior Notes”) (1)
May 15, 2030 4.500% $ 2,000 
Three Months Ended September 30, 2020
CCH — 3.52% Senior Secured Notes due 2039 (the “3.52% CCH Senior Secured Notes”) (2)
December 31, 2039 3.52% 769 
Cheniere — 2028 Cheniere Senior Secured Notes (3)
October 15, 2028 4.625% 2,000 
Nine Months Ended September 30, 2020 total $ 4,769 
(1)Proceeds of the 2030 SPL Senior Notes, along with available cash, were used to redeem all of SPL’s outstanding 5.625% Senior Secured Notes due 2021 (the “2021 SPL Senior Notes”), resulting in the recognition of debt extinguishment costs of $43 million for the nine months ended September 30, 2020 relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.
(2)Proceeds of the 3.52% CCH Senior Secured Notes were used to repay a portion of the outstanding borrowings under the CCH Credit Facility, pay costs associated with certain interest rate derivative instruments that were settled and pay certain fees, costs and expenses incurred in connection with these transactions. The repayment of the CCH Credit Facility resulted in the recognition of debt extinguishment costs of $9 million for the three and nine months ended September 30, 2020 relating to the write off of unamortized debt discounts and issuance costs.
18

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
(3)Proceeds of the 2028 Cheniere Senior Secured Notes, along with $100 million in available cash, were used to prepay approximately $2.1 billion of the outstanding indebtedness of the Cheniere Term Loan Facility, resulting in the recognition of debt extinguishment costs of $14 million for the nine months ended September 30, 2020. The borrowings under the Cheniere Term Loan Facility, which was entered in June 2020 with available commitments of $2.62 billion and subsequently increased to $2.695 billion in July 2020, were used to (1) redeem the remaining outstanding principal amount of the 2025 CCH HoldCo II Convertible Senior Notes with cash at a price of $1,080 per $1,000 principal amount, (2) repurchase $844 million in aggregate principal amount of outstanding 2021 Cheniere Convertible Unsecured Notes at individually negotiated prices from a small number of investors and (3) pay the related fees and expenses. The redemption of the 2025 CCH HoldCo II Convertible Senior Notes and the repurchase of the 2021 Cheniere Convertible Unsecured Notes resulted in the recognition of debt extinguishment costs of $149 million and a reduction in equity associated with reacquisition of the embedded conversion option of $10 million.

Credit Facilities and Delayed Draw Term Loan

Below is a summary of our credit facilities and delayed draw term loan outstanding as of September 30, 2020 (in millions):
2020 SPL Working Capital Facility (1) 2019 CQP Credit Facilities CCH Credit Facility (2) CCH Working Capital Facility Cheniere Revolving Credit Facility Cheniere Term Loan Facility (3)
Original facility size $ 1,200  $ 1,500  $ 8,404  $ 350  $ 750  $ 2,620 
Incremental commitments —  —  1,566  850  500  75 
Less:
Outstanding balance —  —  2,627  141  375  248 
Commitments prepaid or terminated —  750  7,343  —  —  2,075 
Letters of credit issued 413  —  —  293  182  — 
Available commitment $ 787  $ 750  $ —  $ 766  $ 693  $ 372 
Interest rate on available balance
LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%
LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%
LIBOR plus 1.75% or base rate plus 0.75%
LIBOR plus 1.25% - 1.75% or base rate plus 0.25% - 0.75%
LIBOR plus 1.75% - 2.50% or base rate plus 0.75% - 1.50%
(4)
Weighted average interest rate of outstanding balance n/a n/a 1.90% 1.41% 1.90% 2.15%
Maturity date March 19, 2025 May 29, 2024 June 30, 2024 June 29, 2023 December 13, 2022 June 18, 2023
(1)The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL pays a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on the then-current rating of SPL), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.
(2)We prepaid $656 million of outstanding borrowings under the CCH Credit Facility during the three and nine months ended September 30, 2020 using proceeds from the issuance of the 3.52% CCH Senior Secured Notes.
(3)Borrowings under the Cheniere Term Loan Facility are subject to customary conditions precedent. The remaining commitments under the Cheniere Term Loan Facility are expected to be used to repay and/or repurchase a portion of the remaining principal amount of the 2021 Cheniere Convertible Unsecured Notes and for the payment of related fees and expenses. We pay a commitment fee equal to 30% of the margin for LIBOR loans multiplied by the average daily amount of undrawn commitments. If the Cheniere Term Loan Facility is still outstanding on the first anniversary of the Closing Date, as defined by the credit agreement, we will pay duration fees in an amount equal to 0.25% of the aggregate amount of commitments as of July 10, 2020, which was the date the loans were first borrowed under the Cheniere Term Loan Facility (the “Payment Date”). Furthermore, if the Cheniere Term Loan Facility is still outstanding on the second anniversary of the Closing Date, as defined by the credit agreement, we will pay 0.50% of the aggregate amount of commitments as of the Payment Date. Annual administrative fees must also be paid to the administrative agent for the Cheniere Term Loan Facility. Subject to customary exceptions, we are required to make mandatory prepayments with respect to the Cheniere Term Loan Facility using the net proceeds of certain events on a pro rata basis and on terms consistent with required prepayments under the Cheniere Revolving Credit Facility.
19

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
(4)LIBOR plus (1) 2.00% to 2.75% per annum in the first year, (2) 2.50% to 3.25% per annum in the second year and (3) 3.00% to 3.75% per annum in the third year until maturity, or base rate plus (1) 1.00% to 1.75% per annum in the first year, (2) 1.50% to 2.25% per annum in the second year and (3) 2.00% to 2.75% per annum in the third year until maturity.

Convertible Notes

Below is a summary of our convertible notes outstanding as of September 30, 2020 (in millions):
2021 Cheniere Convertible Unsecured Notes 2045 Cheniere Convertible Senior Notes
Aggregate original principal $ 1,000  $ 625 
Add: interest paid-in-kind 309  — 
Less: aggregate principal redeemed (844) — 
Aggregate remaining principal $ 465  $ 625 
Debt component, net of discount and debt issuance costs $ 453  $ 316 
Equity component $ 201  $ 194 
Interest payment method Paid-in-kind Cash
Conversion by us (1) —  (2)
Conversion by holders (1) (3) (4)
Conversion basis Cash and/or stock Cash and/or stock
Conversion value in excess of principal $ —  $ — 
Maturity date May 28, 2021 March 15, 2045
Contractual interest rate 4.875  % 4.25  %
Effective interest rate (5) 8.1  % 9.4  %
Remaining debt discount and debt issuance costs amortization period (6) 0.7 years 24.5 years
(1)Conversion is subject to various limitations and conditions.
(2)Redeemable at any time after March 15, 2020 at a redemption price payable in cash equal to the accreted amount of the $625 million aggregate principal amount of 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) to be redeemed, plus accrued and unpaid interest, if any, to such redemption date.
(3)Initially convertible at $93.64 (subject to adjustment upon the occurrence of certain specified events), provided that the closing price of our common stock is greater than or equal to the conversion price on the conversion date.
(4)Prior to December 15, 2044, convertible only under certain circumstances as specified in the indenture; thereafter, holders may convert their notes regardless of these circumstances. The conversion rate will initially equal 7.2265 shares of our common stock per $1,000 principal amount of the 2045 Cheniere Convertible Senior Notes, which corresponds to an initial conversion price of approximately $138.38 per share of our common stock (subject to adjustment upon the occurrence of certain specified events).
(5)Rate to accrete the discounted carrying value of the convertible notes to the face value over the remaining amortization period.
(6)We amortize any debt discount and debt issuance costs using the effective interest over the period through contractual maturity.

Restrictive Debt Covenants

As of September 30, 2020, each of our issuers was in compliance with all covenants related to their respective debt agreements.

20

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
Interest Expense

Total interest expense, net of capitalized interest, including interest expense related to our convertible notes, consisted of the following (in millions):
  Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Interest cost on convertible notes:
Interest per contractual rate $ 20  $ 65  $ 140  $ 191 
Amortization of debt discount 7  10  41  29 
Amortization of debt issuance costs 1  3  8  9 
Total interest cost related to convertible notes 28  78  189  229 
Interest cost on debt and finance leases excluding convertible notes 388  390  1,167  1,145 
Total interest cost 416  468  1,356  1,374 
Capitalized interest (61) (73) (182) (360)
Total interest expense, net of capitalized interest $ 355  $ 395  $ 1,174  $ 1,014 

Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our debt (in millions):
  September 30, 2020 December 31, 2019
  Carrying
Amount 		Estimated
Fair Value 		Carrying
Amount 		Estimated
Fair Value
Senior notes — Level 2 (1)
$ 24,700  $ 27,109  $ 22,700  $ 24,650 
Senior notes — Level 3 (2)
2,771  3,090  2,002  2,259 
Credit facilities (3) 3,391  3,391  3,283  3,283 
2021 Cheniere Convertible Unsecured Notes (2) 465  474  1,278  1,312 
2025 CCH HoldCo II Convertible Senior Notes (2) —  —  1,578  1,807 
2045 Cheniere Convertible Senior Notes (4) 625  452  625  498 
(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
(2)The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 
(3)The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.
(4)The Level 1 estimated fair value was based on unadjusted quoted prices in active markets for identical liabilities that we had the ability to access at the measurement date.

NOTE 11—LEASES

Our leased assets consist primarily of (1) LNG vessel time charters (“vessel charters”), (2) tug vessels, (3) office space and facilities and (4) land sites, all of which are classified as operating leases except for our tug vessels at the Corpus Christi LNG terminal, which are classified as finance leases.
21

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
The following table shows the classification and location of our right-of-use assets and lease liabilities on our Consolidated Balance Sheets (in millions):
Consolidated Balance Sheets Location September 30, 2020 December 31, 2019
Right-of-use assets—Operating Operating lease assets, net $ 630  $ 439 
Right-of-use assets—Financing Property, plant and equipment, net 54  56 
Total right-of-use assets $ 684  $ 495 
Current operating lease liabilities Current operating lease liabilities $ 160  $ 236 
Current finance lease liabilities Other current liabilities 2  1 
Non-current operating lease liabilities Non-current operating lease liabilities 473  189 
Non-current finance lease liabilities Non-current finance lease liabilities 58  58 
Total lease liabilities $ 693  $ 484 

The following table shows the classification and location of our lease costs on our Consolidated Statements of Operations (in millions):
Consolidated Statements of Operations Location Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Operating lease cost (a) Operating costs and expenses (1) $ 77  $ 163  $ 316  $ 440 
Finance lease cost:
Amortization of right-of-use assets Depreciation and amortization expense —  1  2  3 
Interest on lease liabilities Interest expense, net of capitalized interest 2  2  7  7 
Total lease cost $ 79  $ 166  $ 325  $ 450 
(a) Included in operating lease cost:
Short-term lease costs $ 9  $ 57  $ 60  $ 150 
Variable lease costs paid to the lessor 3  8  12  21 
(1)    Presented in cost of sales, operating and maintenance expense or selling, general and administrative expense consistent with the nature of the asset under lease.

Future annual minimum lease payments for operating and finance leases as of September 30, 2020 are as follows (in millions): 
Years Ending December 31, Operating Leases (1) Finance Leases
2020 $ 74  $ 3 
2021 145  10 
2022 109  10 
2023 96  10 
2024 95  10 
Thereafter 284  136 
Total lease payments 803  179 
Less: Interest (170) (119)
Present value of lease liabilities $ 633  $ 60 
(1)    Does not include $1.5 billion of legally binding minimum lease payments primarily for vessel charters which were executed as of September 30, 2020 but will commence in future period primarily in the next two years and have fixed minimum lease terms of up to seven years.

22

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
The following table shows the weighted-average remaining lease term and the weighted-average discount rate for our operating leases and finance leases:
September 30, 2020 December 31, 2019
Operating Leases Finance Leases Operating Leases Finance Leases
Weighted-average remaining lease term (in years) 8.6 17.9 8.4 18.7
Weighted-average discount rate (1) 5.7% 16.2% 5.2% 16.2%
(1)The finance leases commenced prior to the adoption of the current leasing standard under GAAP. In accordance with previous accounting guidance, the implied rate is based on the fair value of the underlying assets.

The following table includes other quantitative information for our operating and finance leases (in millions):
Nine Months Ended September 30,
2020 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 226  $ 280 
Operating cash flows from finance leases 8  6 
Right-of-use assets obtained in exchange for new operating lease liabilities 412  189 

LNG Vessel Subcharters

From time to time, we sublease certain LNG vessels under charter to third parties while retaining our existing obligation to the original lessor. As of September 30, 2020 and December 31, 2019, we had zero and $9 million in future minimum sublease payments to be received from LNG vessel subcharters, respectively, which will be recognized entirely within 2020. The following table shows the sublease income recognized in other revenues on our Consolidated Statements of Operations (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Fixed Income $ 9  $ 23  $ 61  $ 81 
Variable Income 1  5  24  15 
Total sublease income $ 10  $ 28  $ 85  $ 96 

NOTE 12—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three and nine months ended September 30, 2020 and 2019 (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
LNG revenues (1) $ 1,344  $ 1,995  $ 6,088  $ 6,142 
Regasification revenues 67  66  202  199 
Other revenues 10  17  48  53 
Total revenues from customers 1,421  2,078  6,338  6,394 
Net derivative gains (2) 29  64  148  233 
Other (3) 10  28  85  96 
Total revenues $ 1,460  $ 2,170  $ 6,571  $ 6,723 
(1)    LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. LNG revenues during the three and nine months ended September 30, 2020 included $171 million and $932 million, respectively, in revenues associated with LNG cargoes for which customers have notified us that they will not take delivery, of which $47 million would have otherwise been recognized subsequent to September 30, 2020, if the cargoes were lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $458 million in prior period cancellations that would have otherwise been recognized during the quarter if the cargoes were lifted pursuant to the delivery schedules with the customers. Revenue is generally recognized upon receipt of
23

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.
(2)    See Note 6—Derivative Instruments for additional information about our derivatives.
(3)    Includes revenues from LNG vessel subcharters. See Note 11—Leases for additional information about our subleases.

Contract Assets and Liabilities

The following table shows our contract assets, net, which are classified as other non-current assets, net on our Consolidated Balance Sheets (in millions):
September 30, December 31,
2020 2019
Contract assets, net $ 64  $ 18 

Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the nine months ended September 30, 2020 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.

The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our Consolidated Balance Sheets (in millions):
Nine Months Ended September 30, 2020
Deferred revenues, beginning of period $ 161 
Cash received but not yet recognized 179 
Revenue recognized from prior period deferral (161)
Deferred revenues, end of period $ 179 

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of September 30, 2020 and December 31, 2019:
September 30, 2020 December 31, 2019
Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1)
LNG revenues $ 103.2  10 $ 106.4  11
Regasification revenues 2.2  5 2.4  5
Total revenues $ 105.4  $ 108.8 
(1)    The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

We have elected the following exemptions which omit certain potential future sources of revenue from the table above:
(1)We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
(2)The table above excludes substantially all variable consideration under our SPAs and TUAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not
24

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 37% and 47% of our LNG revenues from contracts included in the table above during the three months ended September 30, 2020 and 2019, respectively, and approximately 35% and 52% of our LNG revenues from contracts included in the table above during the nine months ended September 30, 2020 and 2019, respectively, were related to variable consideration received from customers. During each of the three and nine months ended September 30, 2020 and 2019, approximately 3% of our regasification revenues were related to variable consideration received from customers.

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 considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

NOTE 13—RELATED PARTY TRANSACTIONS

Natural Gas Supply Agreements

SPL and CCL are party to natural gas supply agreements with related parties in the ordinary course of business, to obtain feed gas for the operation of the Liquefaction Projects.

SPL Natural Gas Supply Agreement

The term of the SPL agreement is for five years, which can commence no earlier than November 1, 2021 and no later than November 1, 2022, following the achievement of contractually-defined conditions precedent. As of September 30, 2020, the notional amount for this agreement was 91 TBtu and had a fair value of zero.

CCL Natural Gas Supply Agreement

The term of the CCL agreement extends through March 2022. Under this agreement, CCL recorded $13 million and $3 million in accrued liabilities, as of September 30, 2020 and December 31, 2019, respectively.

The Liquefaction Supply Derivatives related to this agreement are recorded on our Consolidated Balance Sheets as follows (in millions, except notional amount):
September 30, December 31,
2020 2019
Derivative assets $ 1  $ 3 
Non-current derivative assets —  2 
Notional amount, net (in TBtu) 74  120 

We recorded the following amounts on our Consolidated Statements of Operations during the three and nine months ended September 30, 2020 and 2019 related to this agreement (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Cost of sales (a) $ 29  $ 23  $ 77  $ 59 
(a) Included in costs of sales:
Liquefaction Supply Derivative loss
$ (5) $ (1) $ (3) $ (4)

25

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
Natural Gas Transportation and Storage Agreements

SPL is party to various natural gas transportation and storage agreements and CTPL is party to an operational balancing agreement with a related party in the ordinary course of business for the operation of the SPL Project, with initial primary terms of up to 10 years with extension rights. We recorded accrued liabilities of $2 million and zero as of September 30, 2020 and December 31, 2019, respectively, related to these agreements.

Operation and Maintenance Service Agreements

Cheniere LNG O&M Services, LLC (“O&M Services”), our wholly owned subsidiary, provides the development, construction, operation and maintenance services to Midship Pipeline pursuant to agreements in which O&M Services receives an agreed upon fee and reimbursement of costs incurred. O&M Services recorded $2 million during the both three months ended September 30, 2020 and 2019, and $8 million and $9 million in the nine months ended September 30, 2020 and 2019, respectively, of other revenues and $2 million and $3 million of accounts receivable as of September 30, 2020 and December 31, 2019, respectively, for services provided to Midship Pipeline under these agreements.

NOTE 14—INCOME TAXES

We recorded an income tax benefit of $75 million and $3 million during the three months ended September 30, 2020 and 2019, respectively, and an income tax provision of $119 million and zero during the nine months ended September 30, 2020 and 2019, respectively. The effective tax rate for the three and nine months ended September 30, 2020 was 12.9% and 19.3%, respectively, which were lower than the 21% federal statutory rate primarily due to income allocated to non-controlling interest that is not taxable to Cheniere. The effective tax rate for the three months ended September 30, 2020 as compared to the nine months ended September 30, 2020 is lower due to $38 million of tax expense recorded discretely in the first quarter of 2020. The effective tax rate for the three and nine months ended September 30, 2019 was 1.1% and zero, which were lower than the 21% federal statutory rate primarily due to a valuation allowance that was maintained against our federal and state net deferred tax assets.

NOTE 15—SHARE-BASED COMPENSATION
  
We have granted restricted stock shares, restricted stock units, performance stock units and phantom units to employees and non-employee directors under the 2011 Incentive Plan, as amended (the “2011 Plan”), the 2015 Employee Inducement Incentive Plan and the 2020 Incentive Plan that was approved by our shareholders in May 2020.
For the nine months ended September 30, 2020, we granted 1.3 million restricted stock units and 0.3 million performance stock units at target performance to certain employees under the 2011 Plan and the 2020 Incentive Plan. Additionally, 0.2 million incremental shares of our common stock were issued based on performance results from previously-granted performance stock unit awards. Restricted stock units are stock awards that vest over a service period of three years and entitle the holder to receive shares of our common stock upon vesting, subject to restrictions on transfer and to a risk of forfeiture if the recipient terminates employment with us prior to the lapse of the restrictions. Performance stock units provide for cliff vesting after a period of three years with payouts based on metrics dependent upon market and performance achieved over the period from January 1, 2020 through December 31, 2022 compared to pre-established performance targets. The settlement amounts of the awards are based on market and performance metrics which include cumulative distributable cash flow per share, and in certain circumstances, absolute total shareholder return (“ATSR”) of our common stock. Where applicable, the compensation for performance stock units is based on fair value assigned to the market metric of ATSR using a Monte Carlo model upon grant, which remains constant through the vesting period, and a performance metric, which will vary due to changing estimates regarding the expected achievement of the performance metric of cumulative distributable cash flow per share. The number of shares that may be earned at the end of the vesting period ranges from 0% up to 300% of the target award amount. Both restricted stock units and performance stock units will be settled in Cheniere common stock (on a one-for-one basis) and are classified as equity awards.

26

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
Total share-based compensation consisted of the following (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Share-based compensation costs, pre-tax:
Equity awards $ 26  $ 33  $ 86  $ 94 
Liability awards 1  2  2  7 
Total share-based compensation 27  35  88  101 
Capitalized share-based compensation —  (2) (4) (7)
Total share-based compensation expense $ 27  $ 33  $ 84  $ 94 
Tax benefit associated with share-based compensation expense $ 2  $ 2  $ 21  $ 3 

NOTE 16—NET INCOME (LOSS) PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

Basic net income (loss) per share attributable to common stockholders (“EPS”) excludes dilution and is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during the period. Diluted EPS reflects potential dilution and is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued. The dilutive effect of unvested stock is calculated using the treasury-stock method and the dilutive effect of convertible securities is calculated using the treasury or if-converted method, as referenced below.

The following table reconciles basic and diluted weighted average common shares outstanding for the three and nine months ended September 30, 2020 and 2019 (in millions, except per share data):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Weighted average common shares outstanding:    
Basic 252.2  256.0  252.5  256.8 
Dilutive unvested stock —  —  0.7  — 
Diluted 252.2  256.0  253.2  256.8 
Basic and diluted net income (loss) per share attributable to common stockholders $ (1.84) $ (1.25) $ 0.43  $ (1.13)

Potentially dilutive securities that were not included in the diluted net income (loss) per share computations because their effects would have been anti-dilutive were as follows (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Unvested stock (1) 3.1  3.9  2.4  3.9 
Convertible notes
2021 Cheniere Convertible Unsecured Notes (2) —  13.3  —  13.3 
2025 CCH HoldCo II Convertible Senior Notes (3) —  24.4  —  24.4 
2045 Cheniere Convertible Senior Notes 4.5  4.5  4.5  4.5 
Total potentially dilutive common shares 7.6  46.1  6.9  46.1 
(1)Does not include 0.7 million shares for each of the three and nine months ended September 30, 2020 and 0.6 million shares for each of the three and nine months ended September 30, 2019, respectively, of unvested stock because the performance conditions had not yet been satisfied as of the respective dates.
(2)Since we have the intent and ability to settle the remaining outstanding principal amount of the 2021 Cheniere Convertible Unsecured Notes in cash and the excess conversion premium (the “conversion spread”) in either cash or shares, the treasury stock method was applied for calculating any potential dilutive effect of the conversion spread on net income per share for the three and nine months ended September 30, 2020. However, since the average market
27

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
price of our common stock did not exceed the conversion price of our 2021 Cheniere Convertible Unsecured Notes, the conversion spread was excluded from the computation of diluted net income per share for the three and nine months ended September 30, 2020.
(3)Since we redeemed the remaining principal amount of the 2025 CCH HoldCo II Convertible Senior Notes and the related premium in cash, as described in Note 10—Debt, the 2025 CCH HoldCo II Convertible Senior Notes were not included in the computation of net income per share for the three and nine months ended September 30, 2020. There were no shares related to the conversion of the 2025 CCH HoldCo II Convertible Senior Notes included in the computation of diluted net loss per share for the three and nine months ended September 30, 2019, because the substantive non-market based contingencies underlying the eligible conversion date were not met as of September 30, 2019.

NOTE 17—SHARE REPURCHASE PROGRAM

On June 3, 2019, we announced that our Board of Directors (“Board”) authorized a 3-year, $1.0 billion share repurchase program. The following table presents information with respect to repurchases of common stock during the three and nine months ended September 30, 2020 and 2019:
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Aggregate common stock repurchased —  2,477,724  2,875,376  2,522,324 
Weighted average price paid per share $ —  $ 62.99  $ 53.88  $ 63.09 
Total amount paid (in millions) $ —  $ 156  $ 155  $ 159 
As of September 30, 2020, we had up to $596 million of the share repurchase program available. Under the share repurchase program, repurchases can be made from time to time using a variety of methods, which may include open market purchases, privately negotiated transactions or otherwise, all in accordance with the rules of the SEC and other applicable legal requirements. The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by our management based on market conditions and other factors.  The share repurchase program does not obligate us to acquire any particular amount of common stock, and may be modified, suspended or discontinued at any time or from time to time at our discretion.

NOTE 18—COMMITMENTS AND CONTINGENCIES

We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of September 30, 2020, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

Environmental and Regulatory Matters

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. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.

Legal Proceedings

We are, and 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. While the results of these litigation matters and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

28

CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 19—CUSTOMER CONCENTRATION
  
The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable, net and contract assets, net balances of 10% or greater of total accounts receivable, net and contract assets, net from external customers:
Percentage of Total Revenues from External Customers Percentage of Accounts Receivable, Net and Contract Assets, Net from External Customers
Three Months Ended September 30, Nine Months Ended September 30, September 30, December 31,
2020 2019 2020 2019 2020 2019
Customer A * 14% 13% 17% * 12%
Customer B 11% 10% 10% 11% * *
Customer C 15% 13% 11% 12% * 13%
Customer D 13% 10% 10% 12% 15% *
Customer E * * * * 10% *
* Less than 10%

NOTE 20—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental disclosure of cash flow information (in millions): 
Nine Months Ended September 30,
2020 2019
Cash paid during the period for interest on debt, net of amounts capitalized $ 977  $ 771 
Cash paid for income taxes 2  22 

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities was $262 million and $511 million as of September 30, 2020 and 2019, respectively.

29

ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Information Regarding Forward-Looking Statements
This quarterly 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 regarding the amount and timing of share repurchases;
•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;
•statements regarding the outbreak of COVID-19 and its impact on our business and operating results, including any customers not taking delivery of LNG cargoes, the ongoing credit worthiness of our contractual counterparties, any disruptions in our operations or construction of our Trains and the health and safety of our employees, and on our customers, the global economy and the demand for LNG; and
•any other statements that relate to non-historical or future information.
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 quarterly 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
30

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 quarterly 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 quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the fiscal year ended December 31, 2019 and our quarterly report on Form 10-Q for the quarterly period ended March, 31, 2020. 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.

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. Our discussion and analysis includes the following subjects: 
•Overview of Business 
•Overview of Significant Events 
•Impact of COVID-19 and Market Environment
•Liquidity and Capital Resources
•Results of Operations 
•Off-Balance Sheet Arrangements  
•Summary of Critical Accounting Estimates 
•Recent Accounting Standards

Overview of Business
 
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. We own and operate the Sabine Pass LNG terminal in Louisiana, one of the largest LNG production facilities in the world, through our ownership interest in and management agreements with Cheniere Partners, which is a publicly traded limited partnership that we created in 2007. As of September 30, 2020, we owned 100% of the general partner interest and 48.6% of the limited partner interest in Cheniere Partners. We also own and operate the Corpus Christi LNG terminal in Texas, which is wholly owned by us.

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners, through its subsidiary SPL, is currently operating five natural gas liquefaction Trains and is constructing one additional Train for a total production capacity of approximately 30 mtpa of LNG (the “SPL Project”) at the Sabine Pass LNG terminal. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ subsidiary, SPLNG, that include pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 17 Bcfe, two existing marine berths and one under construction that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4 Bcf/d. Cheniere Partners also owns a 94-mile pipeline through its subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.

We also own the Corpus Christi LNG terminal near Corpus Christi, Texas, and are currently operating two Trains and one additional Train is undergoing commissioning for a total production capacity of approximately 15 mtpa of LNG. Additionally, we are operating a 23-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, the “CCL Project”) through our subsidiaries CCL and CCP, respectively. The CCL Project, once fully constructed, will contain three
31

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 have contracted approximately 85% of the total production capacity from the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) on a term basis. This includes volumes contracted under SPAs in which the customers are required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, as well as volumes contracted under integrated production marketing (“IPM”) gas supply agreements.

Additionally, separate from the CCH Group, we are developing an expansion of the Corpus Christi LNG terminal adjacent to the CCL Project (“Corpus Christi Stage 3”) through our subsidiary CCL Stage III for up to seven midscale Trains with an expected total production capacity of approximately 10 mtpa of LNG. We received approval from FERC in November 2019 to site, construct and operate the expansion project.

We remain focused on operational excellence and customer satisfaction. Increasing demand of LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. 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. 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 can make a final investment decision (“FID”).

Overview of Significant Events

Our significant events since January 1, 2020 and through the filing date of this Form 10-Q include the following:
Strategic
•In April 2020, Midship Pipeline Company, LLC (“Midship Pipeline”), in which we have an equity investment, placed into service the Midship natural gas pipeline and related compression and interconnect facilities.
Operational
•As of October 31, 2020, more than 1,250 cumulative LNG cargoes totaling over 85 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.
•In October 2020, feed gas was introduced to Train 3 of the CCL Project.
Financial
•We completed the following debt transactions:
◦In line with our previously announced capital allocation priorities, we prepaid $100 million of outstanding borrowings under the $2.695 billion delayed draw term loan credit agreement (the “Cheniere Term Loan Facility”) in September 2020 with available cash and redeemed $300 million of the 11.0% Convertible Senior Secured Notes due 2025 (the “2025 CCH HoldCo II Convertible Senior Notes”) in March 2020 with available cash.
◦In September 2020, we issued an aggregate principal amount of $2.0 billion of 4.625% Senior Secured Notes due 2028 (the “2028 Cheniere Senior Secured Notes”). The net proceeds were used to prepay approximately $2.0 billion of the outstanding indebtedness of the Cheniere Term Loan Facility.
◦In August 2020, CCH issued an aggregate principal amount of approximately $769 million of 3.52% Senior Secured Notes due 2039 (the “3.52% CCH Senior Secured Notes”). The net proceeds of these notes were used to repay a portion of the outstanding borrowings under the CCH Credit Facility, pay costs associated with certain interest rate derivative instruments that were settled and pay certain fees, costs and expenses incurred in connection with these transactions.
◦In June 2020, we entered into the Cheniere Term Loan Facility with original commitments of $2.62 billion, which in July 2020 was subsequently increased to $2.695 billion. In July 2020, borrowings under the Cheniere Term Loan Facility were used to (1) redeem the remaining outstanding principal amount of the 2025 CCH HoldCo II Convertible Senior Notes, subsequent to the $300 million redemption in March 2020,
32

pursuant to the amended and restated note purchase agreement for the 2025 CCH HoldCo II Convertible Senior Notes which allowed CCH HoldCo II to redeem the outstanding notes with cash at a price of $1,080 per $1,000 principal amount, (2) repurchase $844 million in aggregate principal amount of outstanding 4.875% Convertible Unsecured Notes due 2021 (the “2021 Cheniere Convertible Unsecured Notes”) at individually negotiated prices from a small number of investors and (3) pay the related fees and expenses. The remaining available commitments under the Cheniere Term Loan Facility of $372 million are expected to be used to repay and/or repurchase a portion of the remaining outstanding principal amount of the 2021 Cheniere Convertible Unsecured Notes and for the payment of related fees and expenses.
◦In May 2020, SPL issued an aggregate principal amount of $2.0 billion of 4.500% Senior Secured Notes due 2030 (the “2030 SPL Senior Notes”). Net proceeds of the offering, along with available cash, were used to redeem all of SPL’s outstanding 5.625% Senior Secured Notes due 2021 (the “2021 SPL Senior Notes”).
◦In March 2020, SPL entered into a $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 SPL Working Capital Facility”), which refinanced its previous working capital facility, reduced the interest rate and extended the maturity date to March 2025.
•In May 2020, the date of first commercial delivery was reached under the 20-year SPAs with PT Pertamina (Persero), Naturgy LNG GOM, Limited, Woodside Energy Trading Singapore Pte Ltd, Iberdrola, S.A. and Électricité de France, S.A. relating to Train 2 of the CCL Project.
•In September 2020, Moody’s Investors Service (“Moody’s”) assigned first time ratings of Ba3 and S&P Global Ratings assigned first time ratings of BB to our 2028 Cheniere Senior Secured Notes.
•In August 2020, Moody’s upgraded its rating of CCH’s senior secured debt from Ba1 (Positive Outlook) to Baa3.

Impact of COVID-19 and Market Environment

The business environment in which we operate has been impacted by the recent downturn in the energy market as well as the outbreak of COVID-19 and its progression into a pandemic in March 2020. As a result of these developments, our growth estimates for LNG in 2020 have moderated from previous expectations. Annual LNG demand grew by approximately 13% in 2019 to approximately 360 mtpa. In a report published in the month of April 2020, IHS Markit projected LNG demand in 2020 to reach 363 mtpa, down from a pre-COVID-19 estimate of approximately 377 mtpa. This implies a year-over-year rate of growth of below 1% in 2020 compared to an implied pre-COVID-19 year-over-year growth estimate of approximately 5%. While worldwide demand increased by approximately 3% during the nine months ended September 30, 2020 compared to the comparable period of 2019, we continue to be cautiously optimistic on the outlook. Global economic indicators point to a start of a recovery in some parts of the world but risks from second waves of infections and re-instatement of lockdowns could exert bearish pressures on the market. LNG importers had to cope with strict virus containment measures throughout the first and second quarters of 2020, which negatively impacted gas and LNG demand and resulted in many buyers having to resort to extraordinary measures to manage LNG supply purchases and contractual commitments. Some of these measures included cargo deferrals and cancellations. As the market started to rebalance and storage inventories started to normalize, prices today have recovered from their second quarter lows. As an example, the Dutch Title Transfer Facility (“TTF”), a virtual trading point for natural gas in the Netherlands, settled October at $4.23/MMBtu, which is $3.09/MMBtu higher than the June 2020 settlement. The Japan Korea Marker (“JKM”), an LNG benchmark price assessment for spot physical cargoes delivered ex-ship into certain key markets in Asia, settled October at $4.31/MMBtu, which is $2.25/MMBtu higher than its July price posting. The number of LNG cargoes for which customers have notified us that they will not take delivery have reduced from this summer, a sign that the market is continuing to adjust and rebalance towards equilibrium. We do not expect these events to have a material adverse impact on our forecasted financial results for 2020, due to the highly contracted nature of our business and the fact that customers continue to be obligated to pay fixed fees for cargoes in relation to which they have exercised their contractual right to cancel. As such, during the three and nine months ended September 30, 2020, we recognized $171 million and $932 million, respectively, in revenues associated with LNG cargoes for which customers have notified us that they will not take delivery, of which $47 million would have otherwise been recognized subsequent to September 30, 2020, if the cargoes were lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $458 million in prior period cancellations that would have otherwise been recognized during the quarter if the cargoes were lifted pursuant to the delivery schedules with the customers. We experienced decreased revenues during the three months ended September 30, 2020 because we recognized accelerated revenues associated with LNG cargoes that were scheduled for delivery during the current quarter in the prior quarter, when the customers notified us that they will not take delivery of such cargoes.
33


In addition, in response to the COVID-19 pandemic, we have modified certain business and workforce practices to protect the safety and welfare of our employees who continue to work at our facilities and offices worldwide, as well as implemented certain mitigation efforts to ensure business continuity. In March 2020, we began consulting with a medical advisor, and implemented social distancing through revised shift schedules, work from home policies and designated remote work locations where appropriate, restricted non-essential business travel and began requiring self-screening for employees and contractors. In April 2020, we began providing temporary housing for our workforce for our facilities, implemented temperature testing, incorporated medical and social workers to support employees, enforced prior self-isolation and screening for temporary housing and implemented marine operations with zero contact during loading activities. These measures have resulted in increased costs. While response measures continue to evolve and in most cases have moderated or ceased, we expect to incur incremental operating costs associated with business continuity and protection of our workforce until the risks associated with the pandemic diminish. We have incurred approximately $6 million and $68 million of such costs during the three and nine months ended September 30, 2020, respectively.
Liquidity and Capital Resources

Although results are consolidated for financial reporting, SPL, Cheniere Partners, CCH Group and Cheniere operate with independent capital structures. Our capital requirements include capital and investment expenditures, repayment of long-term debt and repurchase of our shares. We expect the cash needs for at least the next twelve months will be met for each of these independent capital structures as follows:
•SPL through project debt and borrowings, operating cash flows and equity contributions from Cheniere Partners;
•Cheniere Partners through operating cash flows from SPLNG, SPL and CTPL and debt or equity offerings;
•CCH Group through operating cash flows from CCL and CCP, project debt and borrowings and equity contributions from Cheniere; and
•Cheniere through existing unrestricted cash, debt and equity offerings by us or our subsidiaries, operating cash flows, borrowings, services fees from our subsidiaries and distributions from our investment in Cheniere Partners.

The following table provides a summary of our liquidity position at September 30, 2020 and December 31, 2019 (in millions):
September 30, December 31,
2020 2019
Cash and cash equivalents (1) $ 2,091  $ 2,474 
Restricted cash designated for the following purposes:
SPL Project 157  181 
CCL Project 145  80 
Other 220  259 
Available commitments under the following credit facilities:
$1.2 billion Amended and Restated SPL Working Capital Facility (“2015 SPL Working Capital Facility”) —  786 
2020 SPL Working Capital Facility 787  — 
CQP Credit Facilities executed in 2019 (“2019 CQP Credit Facilities”) 750  750 
$1.2 billion CCH Working Capital Facility (“CCH Working Capital Facility”) 766  729 
$1.25 billion Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”) 693  665 
Cheniere Term Loan Facility 372  — 
(1)    Amounts presented include balances held by our consolidated variable interest entity (“VIE”), Cheniere Partners, as discussed in Note 8—Non-controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements. As of September 30, 2020 and December 31, 2019, assets of Cheniere Partners, which are included in our Consolidated Balance Sheets, included $1.3 billion and $1.8 billion, respectively, of cash and cash equivalents.

For additional information regarding our debt agreements, see Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the fiscal year ended December 31, 2019.
34

Sabine Pass LNG Terminal

Liquefaction Facilities

The SPL Project is one of the largest LNG production facilities in the world. Through Cheniere Partners, we are currently operating five Trains and two marine berths at the SPL Project, and are constructing one additional Train. We have received authorization from the FERC to site, construct and operate Trains 1 through 6, as well as for the construction of a third marine berth. We have achieved substantial completion of the first five Trains of the SPL Project and commenced commercial operating activities for each Train at various times starting in May 2016. The following table summarizes the project completion and construction status of Train 6 of the SPL Project as of September 30, 2020:
SPL Train 6
Overall project completion percentage 70.9%
Completion percentage of:
Engineering 97.8%
Procurement 98.2%
Subcontract work 48.0%
Construction 34.6%
Date of expected substantial completion 2H 2022

The following orders have been issued by the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal:
•Trains 1 through 4—FTA countries and non-FTA countries through December 31, 2050, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).
•Trains 1 through 4—FTA countries and non-FTA countries through December 31, 2050, in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).
•Trains 5 and 6—FTA countries and non-FTA countries through December 31, 2050, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).
The DOE issued an order authorizing SPL to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing January 2020, in an aggregate amount up to the equivalent of 600 Bcf of natural gas (however, exports under this order, when combined with exports under the orders above, may not exceed 1,509 Bcf/yr).

An application was filed in September 2019 seeking authorization to make additional exports from the SPL Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 153 Bcf/yr of natural gas, for a total SPL Project export capacity of approximately 1,662 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the SPL Project of the volumes contemplated in the application. In April 2020, the DOE issued an order authorizing SPL to export to FTA countries related to this application, for which the term was subsequently extended through December 31, 2050, but has not yet issued an order authorizing SPL to export to non-FTA countries for the corresponding LNG volume. A corresponding application for authorization to increase the total LNG production capacity of the SPL Project from the currently authorized level to approximately 1,662 Bcf/yr was also submitted to the FERC and is currently pending.

Customers

SPL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 17 years (plus extension rights) with eight third parties for Trains 1 through 6 of the SPL Project. Under these SPAs, the customers will purchase LNG from SPL on a free on board (“FOB”) basis for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to approximately 115% of Henry Hub. The 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. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee
35

component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees under SPL’s SPAs were generally sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion for Trains 1 through 5. After giving effect to an SPA that Cheniere has committed to provide to SPL, the annual fixed fee portion to be paid by the third-party SPA customers would increase to at least $3.3 billion, which is expected to occur upon the date of first commercial delivery of Train 6.

In addition, Cheniere Marketing has an agreement with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers. See Marketing section for additional information regarding agreements entered into by Cheniere Marketing.
Natural Gas Transportation, Storage and Supply

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the SPL Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the SPL Project. As of September 30, 2020, SPL had secured up to approximately 5,051 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts with remaining terms that range up to 10 years, a portion of which is subject to conditions precedent.

Construction

SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 6 of the SPL Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Train 6 of the SPL Project is approximately $2.5 billion, including estimated costs for the third marine berth that is currently under construction. As of September 30, 2020, we have incurred $1.8 billion under this contract.

Regasification Facilities
 
The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG storage capacity of approximately 17 Bcfe. Approximately 2 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal.  Each of Total Gas & Power North America, Inc. (“Total”) and Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually, prior to inflation adjustments, for 20 years that commenced in 2009. Total S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions, and Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

The remaining approximately 2 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, prior to inflation adjustments, continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 5 of the SPL Project, SPL gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Train 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total
36

to SPLNG in accordance with its TUA. During each of the three months ended September 30, 2020 and 2019, SPL recorded $32 million as operating and maintenance expense under this partial TUA assignment agreement. During the nine months ended September 30, 2020 and 2019, SPL recorded $97 million and $72 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Under each of these TUAs, SPLNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to the SPL Project will be financed through project debt and borrowings, cash flows under the SPAs and equity contributions from Cheniere Partners. We believe that with the net proceeds of borrowings, available commitments under the 2020 SPL Working Capital Facility, 2019 CQP Credit Facilities, cash flows from operations and equity contributions from Cheniere Partners, SPL will have adequate financial resources available to meet its currently anticipated capital, operating and debt service requirements with respect to Trains 1 through 6 of the SPL Project. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.
    
The following table provides a summary of our capital resources from borrowings and available commitments for the Sabine Pass LNG Terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in Sources and Uses of Cash), at September 30, 2020 and December 31, 2019 (in millions):
September 30, December 31,
  2020 2019
Senior notes (1) $ 17,750  $ 17,750 
Credit facilities outstanding balance (2) —  — 
Letters of credit issued (3) 413  414 
Available commitments under credit facilities (3) 1,537  1,536 
Total capital resources from borrowings and available commitments (4) $ 19,700  $ 19,700 
(1)    Includes SPL’s 2021 SPL Senior Notes, 6.25% Senior Secured Notes due 2022, 5.625% Senior Secured Notes due 2023, 5.75% Senior Secured Notes due 2024, 5.625% Senior Secured Notes due 2025, 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”), 5.00% Senior Secured Notes due 2027 (the “2027 SPL Senior Notes”), 4.200% Senior Secured Notes due 2028 (the “2028 SPL Senior Notes”), 2030 SPL Senior Notes and 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”) (collectively, the “SPL Senior Notes”), as well as Cheniere Partners’ $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”), $1.1 billion of 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”) and the 4.500% Senior Notes due 2029 (the “2029 CQP Senior Notes”) (collectively, the “CQP Senior Notes”).
(2)     Includes outstanding balances under the 2015 SPL Working Capital Facility, 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities, inclusive of any portion of the 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities that may be used for general corporate purposes.
(3)    Consists of 2015 SPL Working Capital Facility, 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities.
(4)     Does not include equity contributions that may be available from Cheniere’s borrowings and available cash and cash equivalents.

For additional information regarding our debt agreements related to the Sabine Pass LNG Terminal, see Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the fiscal year ended December 31, 2019.

SPL Senior Notes

The SPL Senior Notes are governed by a common indenture (the “SPL Indenture”) and the terms of the 2037 SPL Senior Notes are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain terms and events of default and certain covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by
37

restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. Subject to permitted liens, the SPL Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2030 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is six months before the respective dates of maturity), SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the ‘make-whole’ price (except for the 2037 SPL Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the SPL Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2030 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is within six months of the respective dates of maturity), redeem all or part of such series of the SPL Senior Notes at a redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

Both the 2037 SPL Senior Notes Indenture and the SPL Indenture include restrictive covenants. SPL may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than the current outstanding indebtedness of SPL, including the SPL Senior Notes and the 2020 SPL Working Capital Facility. Under the 2037 SPL Senior Notes Indenture and the SPL Indenture, SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service reserve ratio test of 1.25:1.00 is satisfied. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025 and are fully amortizing according to a fixed sculpted amortization schedule.

2015 SPL Working Capital Facility

In March 2020, SPL terminated the remaining commitments under the 2015 SPL Working Capital Facility. As of December 31, 2019, SPL had $786 million of available commitments, $414 million aggregate amount of issued letters of credit and no outstanding borrowings under the 2015 SPL Working Capital Facility.

2020 SPL Working Capital Facility

In March 2020, SPL entered into the 2020 SPL Working Capital Facility with aggregate commitments of $1.2 billion, which replaced the 2015 SPL Working Capital Facility. The 2020 SPL Working Capital Facility is intended to be used for loans to SPL, swing line loans to SPL and the issuance of letters of credit on behalf of SPL, primarily for (1) the refinancing of the 2015 SPL Working Capital Facility, (2) fees and expenses related to the 2020 SPL Working Capital Facility, (3) SPL and its future subsidiaries’ gas purchase obligations and (4) SPL and certain of its future subsidiaries’ general corporate purposes. SPL may, from time to time, request increases in the commitments under the 2020 SPL Working Capital Facility of up to $800 million. As of September 30, 2020, SPL had $787 million of available commitments, $413 million aggregate amount of issued letters of credit and no outstanding borrowings under the 2020 SPL Working Capital Facility.

The 2020 SPL Working Capital Facility matures on March 19, 2025, but may be extended with consent of the lenders. The 2020 SPL Working Capital Facility provides for mandatory prepayments under customary circumstances.

The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL is restricted from making certain distributions under agreements governing its indebtedness generally until, among other requirements, satisfaction of a 12-month forward-looking and backward-looking 1.25:1.00 debt service reserve ratio test. The obligations of SPL under the 2020 SPL Working Capital Facility are secured by substantially all of the assets of SPL as well as a pledge of all of the membership interests in SPL and certain future subsidiaries of SPL on a pari passu basis by a first priority lien with the SPL Senior Notes.

38

Cheniere Partners

CQP Senior Notes

The CQP Senior Notes are jointly and severally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (each a “Guarantor” and collectively, the “CQP Guarantors”). The CQP Senior Notes are governed by the same base indenture (the “CQP Base Indenture”). The 2025 CQP Senior Notes are further governed by the First Supplemental Indenture, the 2026 CQP Senior Notes are further governed by the Second Supplemental Indenture and the 2029 CQP Senior Notes are further governed by the Third Supplemental Indenture. The indentures governing the CQP Senior Notes contain terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

At any time prior to October 1, 2020 for the 2025 CQP Senior Notes, October 1, 2021 for the 2026 CQP Senior Notes and October 1, 2024 for the 2029 CQP Senior Notes, Cheniere Partners may redeem all or a part of the applicable CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the CQP Senior Notes redeemed, plus the “applicable premium” set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2020 for the 2025 CQP Senior Notes, October 1, 2021 for the 2026 CQP Senior Notes and October 1, 2024 for the 2029 CQP Senior Notes, Cheniere Partners may redeem up to 35% of the aggregate principal amount of the CQP Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 105.250% of the aggregate principal amount of the 2025 CQP Senior Notes, 105.625% of the aggregate principal amount of the 2026 CQP Senior Notes and 104.5% of the aggregate principal amount of the 2029 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. Cheniere Partners also may at any time on or after October 1, 2020 through the maturity date of October 1, 2025 for the 2025 CQP Senior Notes, October 1, 2021 through the maturity date of October 1, 2026 for the 2026 CQP Senior Notes and October 1, 2024 through the maturity date of October 1, 2029 for the 2029 CQP Senior Notes, redeem the CQP Senior Notes, in whole or in part, at the redemption prices set forth in the respective indentures governing the CQP Senior Notes.

The CQP Senior Notes are Cheniere Partners’ senior obligations, ranking equally in right of payment with Cheniere Partners’ other existing and future unsubordinated debt and senior to any of its future subordinated debt. In the event that the aggregate amount of Cheniere Partners’ secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the 2019 CQP Credit Facilities. The obligations under the 2019 CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on substantially all the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities). The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of other senior secured obligations, which include the 2019 CQP Credit Facilities obligations and any future additional senior secured debt obligations.

2019 CQP Credit Facilities

In May 2019, Cheniere Partners entered into the 2019 CQP Credit Facilities, which consisted of the $750 million term loan (“CQP Term Facility”), which was prepaid and terminated upon issuance of the 2029 CQP Senior Notes in September 2019, and the $750 million revolving credit facility (“CQP Revolving Facility”). Borrowings under the 2019 CQP Credit Facilities will be used to fund the development and construction of Train 6 of the SPL Project and for general corporate purposes, subject to a sublimit, and the 2019 CQP Credit Facilities are also available for the issuance of letters of credit. As of both September 30, 2020 and December 31, 2019, Cheniere Partners had $750 million of available commitments and no letters of credit issued or loans outstanding under the 2019 CQP Credit Facilities.

The 2019 CQP Credit Facilities mature on May 29, 2024. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest rate breakage costs. The 2019 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants, and limit Cheniere Partners’ ability to make restricted payments, including distributions, to once per fiscal quarter and one true-up per fiscal quarter as long as certain conditions are satisfied.
39

The 2019 CQP Credit Facilities are unconditionally guaranteed and secured by a first priority lien (subject to permitted encumbrances) on substantially all of Cheniere Partners’ and the CQP Guarantors’ existing and future tangible and intangible assets and rights and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities).

Corpus Christi LNG Terminal

Liquefaction Facilities

We are currently operating two Trains and one marine berth at the CCL Project, commissioning one additional Train and constructing an additional marine berth. We have received authorization from the FERC to site, construct and operate Trains 1 through 3 of the CCL Project. We completed construction of Trains 1 and 2 of the CCL Project and commenced commercial operating activities in February 2019 and August 2019, respectively. The following table summarizes the project completion and construction status of Train 3 of the CCL Project, including the related infrastructure, as of September 30, 2020:
CCL Train 3
Overall project completion percentage 96.7%
Completion percentage of:
Engineering 100.0%
Procurement 100.0%
Subcontract work 98.2%
Construction 91.1%
Expected date of substantial completion 1Q 2021

Separate from the CCH Group, we are also developing Corpus Christi Stage 3 through our subsidiary CCL Stage III, adjacent to the CCL Project. We received approval from FERC in November 2019 to site, construct and operate seven midscale Trains with an expected total production capacity of approximately 10 mtpa of LNG.

The following orders have been issued by the DOE authorizing the export of domestically produced LNG by vessel from the Corpus Christi LNG terminal:
•CCL Project—FTA countries and non-FTA countries through December 31, 2050, up to a combined total of the equivalent of 767 Bcf/yr (approximately 15 mtpa) of natural gas.
•Corpus Christi Stage 3—FTA countries and non-FTA countries through December 31, 2050 in an amount equivalent to 582.14 Bcf/yr (approximately 11 mtpa) of natural gas.

An application was filed in September 2019 to authorize additional exports from the CCL Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 108 Bcf/yr of natural gas, for a total CCL Project export of 875.16 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the CCL Project of the volumes contemplated in the application. In April 2020, the DOE issued an order authorizing CCL to export to FTA countries related to this application, for which the term was subsequently extended through December 31, 2050, but has not yet issued an order authorizing CCL to export to non-FTA countries for the corresponding LNG volume. A corresponding application for authorization to increase the total LNG production capacity of the CCL Project from the currently authorized level to approximately 875.16 Bcf/yr was also submitted to the FERC and is currently pending.

Customers

CCL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 19 years (plus extension rights) with nine third parties for Trains 1 through 3 of the CCL Project. Under these SPAs, the customers will purchase LNG from CCL on a FOB basis for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The 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. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the
40

SPAs as the fixed fee component of the price under our SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under our SPAs. The variable fee under CCL’s SPAs entered into in connection with the development of the CCL Project was sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery for the applicable Train, as specified in each SPA.

In aggregate, the minimum annual fixed fee portion to be paid by the third-party SPA customers is approximately $1.4 billion for Trains 1 and 2 and further increasing to approximately $1.8 billion following the substantial completion of Train 3 of the CCL Project.

In addition, Cheniere Marketing has agreements with CCL to purchase: (1) approximately 15 TBtu per annum of LNG with an approximate term of 23 years, (2) any LNG produced by CCL in excess of that required for other customers at Cheniere Marketing’s option and (3) approximately 44 TBtu of LNG with a term of up to seven years associated with the IPM gas supply agreement between CCL and EOG. See Marketing section for additional information regarding agreements entered into by Cheniere Marketing.

Natural Gas Transportation, Storage and Supply

To ensure CCL is able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CCP and certain third-party pipeline companies. CCL has entered into a firm storage services agreement with a third party to assist in managing variability in natural gas needs for the CCL Project. CCL has also entered into enabling agreements and long-term natural gas supply contracts with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the CCL Project. As of September 30, 2020, CCL had secured up to approximately 3,026 TBtu of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to 11 years, a portion of which is subject to the achievement of certain project milestones and other conditions precedent.
CCL Stage III has also entered into long-term natural gas supply contracts with third parties, and anticipates continuing to enter into such agreements, in order to secure natural gas feedstock for Corpus Christi Stage 3. As of September 30, 2020, CCL Stage III had secured up to approximately 2,361 TBtu of natural gas feedstock through long-term natural gas supply contracts with remaining terms that range up to approximately 15 years, which is subject to the achievement of certain project milestones and other conditions precedent.

A portion of the natural gas feedstock transactions for CCL and CCL Stage III are IPM transactions, in which the natural gas producers are paid based on a global gas market price less a fixed liquefaction fee and certain costs incurred by us.

Construction

CCL entered into separate lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 through 3 of the CCL Project under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause CCL to enter into a change order, or CCL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Train 3, which is currently undergoing commissioning, is approximately $2.4 billion, reflecting amounts incurred under change orders through September 30, 2020. As of September 30, 2020, we have incurred $2.3 billion under this contract.

Final Investment Decision for Corpus Christi Stage 3

FID for Corpus Christi Stage 3 will be subject to, among other things, entering into an EPC contract, obtaining additional commercial support for the project and securing the necessary financing arrangements.
    
41

    Pipeline Facilities

In November 2019, the FERC authorized CCP to construct and operate the pipeline for Corpus Christi Stage 3. The pipeline will be designed to transport 1.5 Bcf/d of natural gas feedstock required by Corpus Christi Stage 3 from the existing regional natural gas pipeline grid.
    Capital Resources

The CCH Group expects to finance the construction costs of the CCL Project from one or more of the following: operating cash flows from CCL and CCP, project debt and equity contributions from Cheniere. The following table provides a summary of the capital resources of the CCH Group from borrowings and available commitments for the CCL Project, excluding equity contributions from Cheniere, at September 30, 2020 and December 31, 2019 (in millions):
September 30, December 31,
  2020 2019
Senior notes (1) $ 7,721  $ 6,952 
2025 CCH HoldCo II Convertible Senior Notes (2)
—  1,000 
Credit facilities outstanding balance (3) 2,768  3,283 
Letters of credit issued (3) 293  471 
Available commitments under credit facilities (3) 766  729 
Total capital resources from borrowings and available commitments (4) $ 11,548  $ 12,435 
(1)        Includes CCH’s 7.000% Senior Secured Notes due 2024, 5.875% Senior Secured Notes due 2025, 5.125% Senior Secured Notes due 2027, 3.700% Senior Secured Notes due 2029, 4.80% Senior Secured Notes due 2039, 3.925% Senior Secured Notes due 2039 and 3.52% CCH Senior Secured Notes (collectively, the “CCH Senior Notes”).
(2)        Aggregate original principal amount before debt discount and debt issuance costs and interest paid-in-kind.
(3)        Includes CCH’s amended and restated credit facility (“CCH Credit Facility”) and CCH Working Capital Facility.
(4)         Does not include equity contributions that may be available from Cheniere’s borrowings and available cash and cash equivalents.

2025 CCH HoldCo II Convertible Senior Notes

In May 2015, CCH HoldCo II issued $1.0 billion aggregate principal amount of the 2025 CCH HoldCo II Convertible Senior Notes on a private placement basis. In May 2018, the amended and restated note purchase agreement under which the 2025 CCH HoldCo II Convertible Senior Notes were issued was subsequently amended in connection with commercialization and financing of Train 3 of the CCL Project and to provide the note holders with certain prepayment rights related thereto consistent with those under the CCH Credit Facility. In February 2020, the amended and restated note purchase agreement for the 2025 CCH HoldCo II Convertible Senior Notes was further amended to allow CCH HoldCo II the option to redeem all or a portion of the outstanding notes with cash at a price of $1,080 per $1,000 principal amount, at the time of any CCH HoldCo II- or noteholder-initiated conversion through September 2, 2020. In March 2020, CCH HoldCo II redeemed an aggregate outstanding principal amount of $300 million and in July 2020, redeemed the remaining outstanding principal amount with borrowings under the Cheniere Term Loan Facility.

CCH Senior Notes

The CCH Senior Notes are jointly and severally guaranteed by CCH’s subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “CCH Guarantor” and collectively, the “CCH Guarantors”). The indentures governing the CCH Senior Notes contain customary terms and events of default and certain covenants that, among other things, limit CCH’s ability and the ability of CCH’s restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of CCH’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to CCH or any of CCH’s restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of CCH and its restricted subsidiaries taken as a whole; or permit any CCH Guarantor to dissolve,
42

liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets. The covenants included in the respective indentures that govern the CCH Senior Notes are subject to a number of important limitations and exceptions.

The CCH Senior Notes are CCH’s senior secured obligations, ranking senior in right of payment to any and all of CCH’s future indebtedness that is subordinated to the CCH Senior Notes and equal in right of payment with CCH’s other existing and future indebtedness that is senior and secured by the same collateral securing the CCH Senior Notes. The CCH Senior Notes are secured by a first-priority security interest in substantially all of CCH’s and the CCH Guarantors’ assets.

At any time prior to six months before the respective dates of maturity for each of the CCH Senior Notes, CCH may redeem all or part of such series of the CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the appropriate indenture, plus accrued and unpaid interest, if any, to the date of redemption. At any time within six months of the respective dates of maturity for each of the CCH Senior Notes, CCH may redeem all or part of such series of the CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.
CCH Credit Facility

In May 2018, CCH amended and restated the CCH Credit Facility to increase total commitments under the CCH Credit Facility from $4.6 billion to $6.1 billion. The obligations of CCH under the CCH Credit Facility are secured by a first priority lien on substantially all of the assets of CCH and its subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in CCH. There were no available commitments under the CCH Credit Facility as of both September 30, 2020 and December 31, 2019. CCH had $2.6 billion and $3.3 billion of loans outstanding under the CCH Credit Facility as of September 30, 2020 and December 31, 2019, respectively.

The CCH Credit Facility matures on June 30, 2024, with principal payments due quarterly commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following the completion of the CCL Project as defined in the common terms agreement and (2) a set date determined by reference to the date under which a certain LNG buyer linked to the last Train of the CCL Project to become operational is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments will be based upon a 19-year tailored amortization, commencing the first full quarter after the completion of Trains 1 through 3 and designed to achieve a minimum projected fixed debt service coverage ratio of 1.50:1.

Under the CCH Credit Facility, CCH is required to hedge not less than 65% of the variable interest rate exposure of its senior secured debt. CCH is restricted from making certain distributions under agreements governing its indebtedness generally until, among other requirements, the completion of the construction of Trains 1 through 3 of the CCL Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.

CCH Working Capital Facility

In June 2018, CCH amended and restated the CCH Working Capital Facility to increase total commitments under the CCH Working Capital Facility from $350 million to $1.2 billion. The CCH Working Capital Facility is intended to be used for loans to CCH (“CCH Working Capital Loans”) and the issuance of letters of credit on behalf of CCH for certain working capital requirements related to developing and operating the CCL Project and for related business purposes. Loans under the CCH Working Capital Facility are guaranteed by the CCH Guarantors. CCH may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed for working capital under the Common Terms Agreement that was entered into concurrently with the CCH Credit Facility. As of September 30, 2020 and December 31, 2019, CCH had $766 million and $729 million of available commitments, $293 million and $471 million aggregate amount of issued letters of credit and $141 million and zero of loans outstanding under the CCH Working Capital Facility, respectively.

The CCH Working Capital Facility matures on June 29, 2023, and CCH may prepay the CCH Working Capital Loans and loans made in connection with a draw upon any letter of credit (“CCH LC Loans”) at any time without premium or penalty upon three business days’ notice and may re-borrow at any time. CCH LC Loans have a term of up to one year. CCH is required to reduce the aggregate outstanding principal amount of all CCH Working Capital Loans to zero for a period of five consecutive business days at least once each year.

43

The CCH Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. The obligations of CCH under the CCH Working Capital Facility are secured by substantially all of the assets of CCH and the CCH Guarantors as well as all of the membership interests in CCH and each of the CCH Guarantors on a pari passu basis with the CCH Senior Notes and the CCH Credit Facility.

Cheniere

Senior Notes

In September 2020, we issued an aggregate principal amount of $2.0 billion of 2028 Cheniere Senior Secured Notes, the proceeds of which were used to prepay a portion of the outstanding indebtedness under the Cheniere Term Loan Facility and to pay related fees and expenses. The associated indentures (“Cheniere Indenture”) contain customary terms and events of default and certain covenants that, among other things, limit our ability to create liens or other encumbrances, enter into sale-leaseback transactions and merge or consolidate with other entities or sell all or substantially all of our assets. The Cheniere Indenture covenants are subject to a number of important limitations and exceptions.

At any time prior to October 15, 2023, we may redeem all or a part of the 2028 Cheniere Senior Secured Notes at a redemption price equal to 100% of the aggregate principal amount thereof, plus the “applicable premium” and accrued and unpaid interest, if any, to but not including the date of redemption. We also may, at any time prior to October 15, 2023, redeem up to 40% of the aggregate principal amount of the 2028 Cheniere Senior Secured Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 104.625% of the aggregate principal amount of the notes being redeemed, plus accrued and unpaid interest, if any, to but not including, the date of redemption. At any time on or after October 15, 2023 through the maturity date of October 15, 2028, we may redeem all or part of the 2028 Cheniere Senior Secured Notes at the redemption prices described in the Cheniere Indenture.

The 2028 Cheniere Senior Secured Notes are our general senior obligations and rank senior in right of payment to all of our future obligations that are, by their terms, expressly subordinated in right of payment to the 2028 Cheniere Senior Secured Notes and equally in right of payment with all of our other existing and future unsubordinated indebtedness. The 2028 Cheniere Senior Secured Notes will initially be secured on a first-priority basis by a lien on substantially all of our assets and equity interests in our direct subsidiaries (other than certain excluded subsidiaries) (the “Collateral”), which liens will rank pari passu with the liens securing the Cheniere Revolving Credit Facility and Cheniere Term Loan Facility. The 2028 Cheniere Senior Secured Notes will remain secured as long as (1) there are any obligations or undrawn commitments outstanding under the Cheniere Term Loan Facility that are secured by liens on the Collateral or (2) the outstanding aggregate principal amount of our secured indebtedness exceeds $1.25 billion. As of September 30, 2020, the 2028 Cheniere Senior Secured Notes are not guaranteed by any of our subsidiaries. In the future, the 2028 Cheniere Senior Secured Notes will be guaranteed by our subsidiaries who guarantee our other material indebtedness.

Convertible Notes

In November 2014, we issued an aggregate principal amount of $1.0 billion of the 2021 Cheniere Convertible Unsecured Notes. The 2021 Cheniere Convertible Unsecured Notes are convertible at the option of the holder into our common stock at the then applicable conversion rate, provided that the closing price of our common stock is greater than or equal to the conversion price on the date of conversion. In July 2020, we repurchased $844 million in aggregate principal amount of the outstanding 2021 Cheniere Convertible Unsecured Notes at individually negotiated prices from a small number of investors.

In March 2015, we issued $625 million aggregate principal amount of 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”). We have the right, at our option, at any time after March 15, 2020, to redeem all or any part of the 2045 Cheniere Convertible Senior Notes at a redemption price equal to the accreted amount of the 2045 Cheniere Convertible Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to such redemption date.

We have the option to satisfy the conversion obligation for the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes with cash, common stock or a combination thereof.

44

Cheniere Revolving Credit Facility

In December 2018, we amended and restated the Cheniere Revolving Credit Facility to increase total commitments under the Cheniere Revolving Credit Facility from $750 million to $1.25 billion. The Cheniere Revolving Credit Facility is intended to fund, through loans and letters of credit, equity capital contributions to CCH HoldCo II and its subsidiaries for the development of the CCL Project and, provided that certain conditions are met, for general corporate purposes. As of September 30, 2020 and December 31, 2019, we had $693 million and $665 million of available commitments, $182 million and $585 million aggregate amount of issued letters of credit and $375 million and zero of loans outstanding under the Cheniere Revolving Credit Facility, respectively.

The Cheniere Revolving Credit Facility matures on December 13, 2022 and contains representations, warranties and affirmative and negative covenants customary for companies like us with lenders of the type participating in the Cheniere Revolving Credit Facility that limit our ability to make restricted payments, including distributions, unless certain conditions are satisfied, as well as limitations on indebtedness, guarantees, hedging, liens, investments and affiliate transactions. Under the Cheniere Revolving Credit Facility, we are required to ensure that the sum of our unrestricted cash and the amount of undrawn commitments under the Cheniere Revolving Credit Facility is at least equal to the lesser of (1) 20% of the commitments under the Cheniere Revolving Credit Facility and (2) $200 million (the “Liquidity Covenant”). However, at any time that the aggregate principal amount of outstanding loans plus drawn and unreimbursed letters of credit under the Cheniere Revolving Credit Facility is greater than 30% of aggregate commitments under the Cheniere Revolving Credit Facility, the Liquidity Covenant will not apply and we will instead be governed by a quarterly non-consolidated leverage ratio covenant not to exceed 5.75:1.00 (the “Springing Leverage Covenant”).

The Cheniere Revolving Credit Facility is secured by a first priority security interest (subject to permitted liens and other customary exceptions) in substantially all of our assets, including our interests in our direct subsidiaries (excluding CCH HoldCo II and certain other subsidiaries).

Cheniere Term Loan Facility

In June 2020, we entered into the Cheniere Term Loan Facility, which was subsequently increased to $2.695 billion in July 2020. In July 2020, borrowings under the Cheniere Term Loan Facility were used to (1) redeem the outstanding principal amount of the 2025 CCH HoldCo II Convertible Senior Notes, (2) repurchase $844 million in aggregate principal amount of outstanding 2021 Cheniere Convertible Unsecured Notes at individually negotiated prices from a small number of investors and (3) pay the related fees and expenses. The remaining commitments under the Cheniere Term Loan Facility are expected to be used to repay and/or repurchase a portion of the remaining principal amount of the 2021 Cheniere Convertible Unsecured Notes and for the payment of related fees and expenses. In September 2020, we prepaid approximately $2.1 billion of the outstanding indebtedness of the Cheniere Term Loan Facility with net proceeds from the 2028 Cheniere Senior Secured Notes and available cash. As of September 30, 2020, we had $372 million of available commitments and $248 million of loans outstanding under the Cheniere Term Loan Facility.
The Cheniere Term Loan Facility matures on June 18, 2023. Loans under the Cheniere Term Loan Facility may be voluntarily prepaid, in whole or in part, at any time, without premium or penalty. Borrowings under the Cheniere Term Loan Facility are subject to customary conditions precedent. The Cheniere Term Loan Facility includes representations, warranties, affirmative and negative covenants and events of default customary for companies like us with lenders of the type participating in the Cheniere Term Loan Facility and consistent with the equivalent provisions contained in the Cheniere Revolving Credit Facility.

The Cheniere Term Loan Facility is secured by a first priority security interest (subject to permitted liens and other customary exceptions) on a pari passu basis with the Cheniere Revolving Credit Facility in substantially all of our assets and equity interests in direct subsidiaries (other than certain excluded subsidiaries). Upon redemption of the 2025 CCH HoldCo II Convertible Senior Notes in July 2020, the equity interests in CCH HoldCo II were pledged as collateral to secure the obligations under the Cheniere Revolving Credit Facility and the Cheniere Term Loan Facility.

Cash Receipts from Subsidiaries

Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of September 30, 2020, we owned a 48.6% limited partner interest in Cheniere Partners in the form of 239.9 million common units. In July 2020, the
45

financial tests required for conversion of Cheniere Partners’ subordinated units, all of which were held by us, were met under the terms of Cheniere Partners’ partnership agreement and effective August 17, 2020, the first business day following the payment of the quarterly distribution, all of Cheniere Partners’ subordinated units were automatically converted into common units on a one-for-one basis and the subordination period was terminated. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners. We are eligible to receive quarterly equity distributions from Cheniere Partners related to our ownership interests and our incentive distribution rights.

We also receive fees for providing management services to some of our subsidiaries. We received $83 million and $79 million in total service fees from these subsidiaries during the each of the nine months ended September 30, 2020 and 2019, respectively.

Share Repurchase Program

On June 3, 2019, we announced that our Board of Directors (“Board”) authorized a 3-year, $1.0 billion share repurchase program. During the nine months ended September 30, 2020, we repurchased an aggregate of 2.9 million shares of our common stock for $155 million, for a weighted average price per share of $53.88. During the nine months ended September 30, 2019, we repurchased an aggregate of 2.5 million shares of our common stock for $159 million, for a weighted average price per share of $63.09. As of September 30, 2020, we had up to $596 million of the share repurchase program available. Under the share repurchase program, repurchases can be made from time to time using a variety of methods, which may include open market purchases, privately negotiated transactions or otherwise, all in accordance with the rules of the SEC and other applicable legal requirements. The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by our management based on market conditions and other factors.  The share repurchase program does not obligate us to acquire any particular amount of common stock, and may be modified, suspended or discontinued at any time or from time to time at our discretion.

Marketing

We market and sell LNG produced by the Liquefaction Projects that is not required for other customers through our integrated marketing function. We have, and continue to develop, a portfolio of long-, medium- and short-term SPAs to transport and unload 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. As of September 30, 2020, we have sold or have options to sell approximately 4,747 TBtu of LNG to be delivered to customers between 2020 and 2045.  The cargoes have been sold either on a FOB basis (delivered to the customer at the Sabine Pass LNG terminal or the Corpus Christi LNG terminal, as applicable) or a delivered at terminal (“DAT”) basis (delivered to the customer at their LNG receiving terminal). We have chartered LNG vessels to be utilized for cargoes sold on a DAT basis. In addition, we have entered into a long-term agreement to sell LNG cargoes on a DAT basis that is conditioned upon the buyer achieving certain milestones.

Cheniere Marketing entered into uncommitted trade finance facilities with available commitments of $254 million as of September 30, 2020, primarily to be used for the purchase and sale of LNG for ultimate resale in the course of its operations. The finance facilities are intended to be used for advances, guarantees or the issuance of letters of credit or standby letters of credit on behalf of Cheniere Marketing. As of September 30, 2020 and December 31, 2019, Cheniere Marketing had $21 million and $41 million, respectively, in standby letters of credit and guarantees outstanding under the finance facilities. As of September 30, 2020 and December 31, 2019, there were no loans outstanding under the finance facilities. Cheniere Marketing pays interest or fees on utilized commitments.

Corporate and Other Activities
 
We are required to maintain corporate and general and administrative functions to serve our business activities described above.  The development of our 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 an FID.

We have made an equity investment in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline. Midship Pipeline operates the Midship Project with current capacity of up to 1.1 million Dekatherms per day that connects new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the Liquefaction Projects. The Midship Project was placed in service in April 2020.
46


Restrictive Debt Covenants

As of September 30, 2020, each of our issuers was in compliance with all covenants related to their respective debt agreements.

LIBOR

The use of LIBOR is expected to be phased out by the end of 2021. It is currently unclear whether LIBOR will be utilized beyond that date or whether it will be replaced by a particular rate. We intend to continue working with our lenders and counterparties to pursue any amendments to our debt and derivative agreements that are currently subject to LIBOR and will continue to monitor, assess and plan for the phase out of LIBOR.
Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the nine months ended September 30, 2020 and 2019 (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. 
Nine Months Ended September 30,
2020 2019
Operating cash flows $ 765  $ 1,092 
Investing cash flows (1,545) (2,658)
Financing cash flows 399  1,527 
Net decrease in cash, cash equivalents and restricted cash (381) (39)
Cash, cash equivalents and restricted cash—beginning of period 2,994  3,156 
Cash, cash equivalents and restricted cash—end of period $ 2,613  $ 3,117 

Operating Cash Flows

Our operating cash net inflows during the nine months ended September 30, 2020 and 2019 were $765 million and $1,092 million, respectively. The $327 million decrease in operating cash inflows in 2020 compared to 2019 was primarily related to repayment of paid-in-kind interest related to the repurchase of the 2025 CCH HoldCo II Convertible Senior Notes and a portion of the 2021 Cheniere Convertible Unsecured Notes, which was offset by the increased net income that was primarily due to additional LNG volume available to be sold from additional Trains that have reached substantial completion between the periods, a portion of which the customers elected not to take delivery but were required to pay a fixed fee with respect to the contracted volumes.

Investing Cash Flows

Investing cash net outflows during the nine months ended September 30, 2020 and 2019 were $1,545 million and $2,658 million, respectively, and were primarily used to fund the construction costs for the Liquefaction Projects. These costs are capitalized as construction-in-process until achievement of substantial completion. Additionally, we invested $100 million and $70 million in Midship Holdings, our equity method investment, during the nine months ended September 30, 2020 and 2019, respectively.

Financing Cash Flows

Financing cash net outflows during the nine months ended September 30, 2020 were $399 million, primarily as a result of:
•issuance of an aggregate principal amount of $2.0 billion of the 2030 SPL Senior Notes, which along with cash on hand was used to redeem all of the outstanding 2021 SPL Senior Notes;
47

•$2.3 billion of borrowings under the Cheniere Term Loan Facility, which were used to redeem the outstanding principal amount of $1.0 billion of the 2025 CCH HoldCo II Convertible Senior Notes and repurchase $513 million principal amount of the 2021 Cheniere Convertible Unsecured Notes;
•issuance of an aggregate principal amount of $2.0 billion of the 2028 Cheniere Senior Secured Notes, which along with available cash, were used to prepay the $2.1 billion outstanding indebtedness of the Cheniere Term Loan Facility;
•issuance of an aggregate principal amount of $769 million of the 3.52% CCH Senior Secured Notes, which the proceeds were partly used to repay a portion of the outstanding borrowings under the CCH Credit Facility;
•$455 million of borrowings and $80 million of repayments under the Cheniere Revolving Credit Facility;
•$141 million of borrowings and $656 million of repayments under the CCH Working Capital Facility;
•$124 million of debt issuance costs primarily related to up-front fees paid upon the closing of the above transactions;
•$468 million of distributions to non-controlling interest by Cheniere Partners;
•$155 million paid to repurchase approximately 3 million shares of our common stock under the share repurchase program;
•$43 million paid for tax withholdings for share-based compensation; and
•$170 million of debt modification or extinguishment costs related to the above transactions.

Financing cash net inflows during the nine months ended September 30, 2019 were $1,527 million, primarily as a result of:
•issuance of an aggregate principal amount of $1.5 billion of the 2029 CQP Senior Notes, which was used to prepay the outstanding balance of the term loan under the 2019 CQP Credit Facilities;
•$982 million of borrowings and $797 million of repayments under the CCH Credit Facility;
•$730 million of borrowings and repayments under the 2019 CQP Credit Facilities;
•issuance of an aggregate principal of $727 million of the 4.80% CCH Senior Notes, which was used to prepay a portion of the outstanding balance of the CCH Credit Facility;
•$481 million of borrowings and $649 million in repayments under the CCH Working Capital Facility;
•$439 million of distributions to non-controlling interest by Cheniere Partners;
•$159 million paid to repurchase our common stock under the share repurchase program;
•$61 million of net repayments related to our Cheniere Marketing trade financing facilities;
•$38 million of debt issuance costs primarily related to up-front fees paid upon the closing of the 2019 CQP Credit Facilities, 2029 CQP Senior Notes and the 4.80% CCH Senior Notes; and
•$19 million paid for tax withholdings for share-based compensation.

48

Results of Operations

The following charts summarize the number of Trains that were in operation during the year ended December 31, 2019 and the nine months ended September 30, 2020 and total revenues and total LNG volumes loaded from our Liquefaction Projects (including both operational and commissioning volumes) during the nine months ended September 30, 2020 and 2019:

LNG-20200930_G3.JPG

LNG-20200930_G4.JPG LNG-20200930_G5.JPG

The following table summarizes the volumes of operational and commissioning LNG cargoes that were loaded from the Liquefaction Projects, which were recognized on our Consolidated Financial Statements during the three and nine months ended September 30, 2020:
Three Months Ended September 30, 2020 Nine Months Ended September 30, 2020
(in TBtu) Operational Commissioning Operational Commissioning
Volumes loaded during the current period 187  —  920  — 
Volumes loaded during the prior period but recognized during the current period 2  —  33  — 
Less: volumes loaded during the current period and in transit at the end of the period (21) —  (21) — 
Total volumes recognized in the current period 168  —  932  — 

49

Our consolidated net loss attributable to common stockholders was $463 million, or $1.84 per share (basic and diluted), for the three months ended September 30, 2020, compared to $318 million, or $1.25 per share (basic and diluted), in the three months ended September 30, 2019. This $145 million increase in net loss attributable to common stockholders in 2020 was primarily attributable to the impact of prior period elections by our long-term SPA customers to exercise their contractual right to not take delivery of LNG cargoes that were scheduled to be delivered this quarter. Additionally, net loss attributable to common stockholders increased due to losses on modification or extinguishment of debt from refinancing activities to address near-term maturities and higher cost debt and from increased loss on equity method investments, partially offset by (1) increased net loss attributable to non-controlling interest, (2) reduction in interest rate derivative losses, (3) increased income tax benefit and (4) decreased interest expense, net of capitalized interest.

Our consolidated net income attributable to common stockholders was $109 million, or $0.43 per share (basic and diluted), for the nine months ended September 30, 2020, compared to net loss attributable to common stockholders of $291 million, or $1.13 per share (basic and diluted), in the nine months ended September 30, 2019. This $400 million increase in net income attributable to common stockholders in 2020 was primarily attributable to additional LNG volume available to be sold from additional Trains that have reached substantial completion between the periods, a portion of which the customers elected not to take delivery but were required to pay a fixed fee with respect to the contracted volumes, and increased gains from commodity derivatives to secure natural gas feedstock for the Liquefaction Projects, partially offset by increases in (1) loss on modification or extinguishment of debt from refinancing activities of higher cost debt, (2) operating and maintenance expense, (3) interest expense, net of capitalized interest, (4) depreciation and amortization expense, (5) income tax provision and (6) increased loss on equity method investments.

We enter into derivative instruments to manage our exposure to (1) changing interest rates, (2) commodity-related marketing and price risks and (3) foreign exchange volatility. Derivative instruments are reported at fair value on our Consolidated Financial Statements. In some cases, the underlying transactions economically hedged receive accrual accounting treatment, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, use of derivative instruments may increase the volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors.

Revenues
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2020 2019 Change 2020 2019 Change
LNG revenues $ 1,373  $ 2,059  $ (686) $ 6,236  $ 6,375  $ (139)
Regasification revenues 67  66  1  202  199  3 
Other revenues 20  45  (25) 133  149  (16)
Total revenues $ 1,460  $ 2,170  $ (710) $ 6,571  $ 6,723  $ (152)

Total revenues decreased during the three months ended September 30, 2020 from the three months ended September 30, 2019, primarily as a result of decreased volumes recognized as revenues between the periods due to LNG cargoes for which customers have notified us that they will not take delivery, although this decrease was partially offset by the revenues associated with LNG cargoes for which customers have notified us that they will not take delivery. Total revenues decreased during the nine months ended September 30, 2020 from the nine months ended September 30, 2019, primarily as a result of decreased revenues recognized by our integrated marketing function due to the recent downturn in the energy market. LNG revenues during the three and nine months ended September 30, 2020 included $171 million and $932 million, respectively, in revenues associated with LNG cargoes for which customers have notified us that they will not take delivery, of which $47 million would have otherwise been recognized subsequent to September 30, 2020, if the cargoes were lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $458 million in prior period cancellations that would have otherwise been recognized during the quarter if the cargoes were lifted pursuant to the delivery schedules with the customers. We experienced decreased revenues during the three months ended September 30, 2020 because we recognized accelerated revenues associated with LNG cargoes that were scheduled for delivery during the current quarter in the prior quarter, when the customers notified us that they will not take delivery of such cargoes. We expect our LNG revenues to increase in the future upon Train 3 of the CCL Project and Train 6 of the SPL Project becoming operational.

50

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. We realized offsets to LNG terminal costs of $99 million corresponding to 23 TBtu of LNG in the three months ended September 30, 2019 and $301 million corresponding to 51 TBtu of LNG in the nine months ended September 30, 2019 that were related to the sale of commissioning cargoes from the Liquefaction Projects. We did not realize any offsets to LNG terminal costs during the three and nine months ended September 30, 2020.
Also included in LNG revenues are sale of unutilized natural gas procured for the liquefaction process, gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery, and revenues from arrangements in which we financially settled previously-scheduled LNG cargo sales without physical delivery. We recognized revenues of $272 million and $134 million during the three months ended September 30, 2020 and 2019, respectively, and $545 million and $451 million during the nine months ended September 30, 2020 and 2019, respectively, related to these transactions.

The following table presents the components of LNG revenues and the corresponding LNG volumes sold:
Three Months Ended September 30, Nine Months Ended September 30,
  2020 2019 2020 2019
LNG revenues (in millions):
LNG from the Liquefaction Projects sold under third party long-term agreements (1) $ 780  $ 1,496  $ 3,931  $ 4,406 
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements 65  398  540  1,303 
LNG procured from third parties 85  31  288  215 
LNG revenues associated with cargoes not delivered per customer notification (2) 171  —  932  — 
Other revenues and derivative gains 272  134  545  451 
Total LNG revenues $ 1,373  $ 2,059  $ 6,236  $ 6,375 
Volumes delivered as LNG revenues (in TBtu):
LNG from the Liquefaction Projects sold under third party long-term agreements (1) 145  276  764  753 
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements 23  88  168  245 
LNG procured from third parties 31  8  79  31 
Total volumes delivered as LNG revenues 199  372  1,011  1,029 
(1)     Long-term agreements include agreements with a tenure of 12 months or more.
(2)    LNG revenues include revenues with no corresponding volumes attributable to LNG cargoes for which customers have notified us that they will not take delivery.

Operating costs and expenses
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2020 2019 Change 2020 2019 Change
Cost of sales $ 768  $ 1,267  $ (499) $ 2,295  $ 3,758  $ (1,463)
Operating and maintenance expense 317  308  9  988  824  164 
Development expense —  2  (2) 5  6  (1)
Selling, general and administrative expense 70  72  (2) 224  222  2 
Depreciation and amortization expense 233  213  20  699  561  138 
Impairment expense and loss on disposal of assets —  1  (1) 5  7  (2)
Total operating costs and expenses $ 1,388  $ 1,863  $ (475) $ 4,216  $ 5,378  $ (1,162)

51

Our total operating costs and expenses decreased during the three and nine months ended September 30, 2020 from the three and nine months ended September 30, 2019, primarily as a result of decreased cost of sales, partially offset by increased operating and maintenance expense and depreciation and amortization expense from additional operating Trains between the periods.

Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Projects, to the extent those costs are not utilized for the commissioning process. Cost of sales decreased during the three months ended September 30, 2020 from the three months ended September 30, 2019, primarily due to decreased volumes of natural gas feedstock between the periods and decreased vessel charter costs. Cost of sales decreased during the nine months ended September 30, 2020 from the nine months ended September 30, 2019, primary due to decreased pricing of natural gas feedstock between the periods, increased fair value of commodity derivatives to secure natural gas feedstock for the Liquefaction Projects due to favorable shifts in long-term forward prices relative to our hedged position and decreased vessel charter costs. Partially offsetting these decreases in both the three and nine months ended September 30, 2020 were increases in costs associated with sale of unutilized natural gas procured for the liquefaction process and a portion of derivative instruments that settle through physical delivery. Cost of sales also includes port and canal fees, variable transportation and storage costs and the sale of natural gas procured for the liquefaction process and other costs to convert natural gas into LNG.

Operating and maintenance expense primarily includes costs associated with operating and maintaining the Liquefaction Projects. Additionally, operating and maintenance expense includes costs incurred in response to the COVID-19 pandemic, as further described earlier in Impact of COVID-19 and Market Environment. Excluding the costs incurred in response to the COVID-19 pandemic, operating and maintenance expense (including affiliates) did not materially change between the three months ended September 30, 2020 and 2019, and increased during the nine months ended September 30, 2020 from the nine months ended September 30, 2019, primarily due to increased natural gas transportation and storage capacity demand charges, increased TUA reservation charges due to Total under the partial TUA assignment agreement and increased payroll and benefit costs from increased headcount from additional Trains operating at the Liquefaction Projects between the periods. Operating and maintenance expense also includes insurance and regulatory and other operating costs.
Depreciation and amortization expense increased during the three and nine months ended September 30, 2020 from the three and nine months ended September 30, 2019 as a result of an increased number of operational Trains, as the related assets began depreciating upon reaching substantial completion.

We expect our operating costs and expenses to generally increase in the future upon Train 3 of the CCL Project and Train 6 of the SPL Project achieving substantial completion, although we expect certain costs will not proportionally increase with the number of operational Trains as cost efficiencies will be realized.

Other expense
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2020 2019 Change 2020 2019 Change
Interest expense, net of capitalized interest $ 355  $ 395  $ (40) $ 1,174  $ 1,014  $ 160 
Loss on modification or extinguishment of debt 171  27  144  215  27  188 
Interest rate derivative loss, net —  78  (78) 233  187  46 
Other expense, net 129  70  59  115  38  77 
Total other expense $ 655  $ 570  $ 85  $ 1,737  $ 1,266  $ 471 

Interest expense, net of capitalized interest, decreased during the three months ended September 30, 2020 from the comparable period in 2019 as a result of the redemption of the remaining outstanding principal amount of the 2025 CCH HoldCo II Convertible Senior Notes in July 2020 and the refinancing of a portion of the outstanding balance under the CCH Credit Facility and decrease in associated interest rates, partially offset by an increase in interest cost for the new senior notes issued by CCH and a decrease in the portion of total interest costs that is eligible for capitalization, as additional Trains of the Liquefaction Projects completed construction between the periods. Interest expense, net of capitalized interest, increased during the three and nine months ended September 30, 2020 from the three and nine months ended September 30, 2019 primarily as a result of a decrease in the portion of total interest costs that is eligible for capitalization as additional Trains of the Liquefaction Projects completed construction between the periods. During the three months ended September 30, 2020 and 2019, we incurred $416 million and $468 million of total interest cost, respectively, of which we capitalized $61 million and
52

$73 million, respectively, which was primarily related to interest costs incurred to construct the remaining assets of the Liquefaction Projects. During both the nine months ended September 30, 2020 and 2019, we incurred $1.4 billion of total interest cost which was primarily related to interest costs incurred to construct the remaining assets of the Liquefaction Projects. We capitalized $182 million and $360 million of interest during the nine months ended September 30, 2020 and 2019, respectively.

Loss on modification or extinguishment of debt increased during the three and nine months ended September 30, 2020 from the comparable periods in 2019 due to the recognition of debt extinguishment costs resulting from (1) the redemption of the remaining outstanding principal amount of the 2025 CCH HoldCo II Convertible Senior Notes and partial repurchase of the 2021 Cheniere Convertible Unsecured Notes, (2) refinancing of the 2021 SPL Senior Notes in May 2020, (3) the prepayment of approximately $2.1 billion of the outstanding indebtedness of the Cheniere Term Loan Facility and (4) the prepayment of a portion of the outstanding balance of the CCH Credit Facility using proceeds from the issuance of senior notes or as part of Cheniere’s capital allocation framework.

Interest rate derivative loss, net decreased during the three months ended September 30, 2020 compared to the three months ended September 30, 2019, primarily due to a favorable shift in the long-term forward LIBOR curve between the periods. Interest rate derivative loss, net increased during the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019, primarily due to an unfavorable shift in the long-term forward LIBOR curve between the periods.

Other expense, net increased during the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019 due to an increase in impairment losses recognized related to our equity method investments between the periods and a decrease in interest income earned on our cash and cash equivalents. We recognized other-than-temporary impairment losses of $129 million related to our investment in Midship Holdings during the three and nine months ended September 30, 2020. Impairment was precipitated primarily due to declining market conditions in the energy industry and customer credit risk, resulting in a reduction in the fair value of our equity interests. We recognized losses of $87 million during the three and nine months ended September 30, 2019 related to our investments in certain equity method investees, including Midship Holdings. Impairments were primarily the result of cost overruns and extended construction timelines for operating infrastructure of our investees’ projects.

Income tax benefit (provision)
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2020 2019 Change 2020 2019 Change
Income (loss) before income taxes and non-controlling interest $ (583) $ (263) $ (320) $ 618  $ 79  $ 539 
Income tax benefit (provision) 75  3  72  (119) —  (119)
Effective tax rate 12.9  % 1.1  % 19.3  % —  %

The effective tax rates for the three and nine months ended September 30, 2020 were lower than the 21% federal statutory rate primarily due to income allocated to non-controlling interest that is not taxable to Cheniere. The effective tax rate for the three months ended September 30, 2020 as compared to the nine months ended September 30, 2020 is lower due to $38 million of tax expense recorded discretely in the first quarter of 2020. The effective tax rate for the three and nine months ended September 30, 2019 is lower than the 21% federal statutory rate primarily due to maintaining a valuation allowance against our federal deferred tax assets.

On July 28, 2020, the U.S. Department of the Treasury released final regulations and proposed regulations providing guidance on the business interest expense limitation under Section 163(j) of the Internal Revenue Code. We are currently in the process of evaluating the effect of these regulations on our Consolidated Financial Statements and related disclosures.

53

Net income (loss) attributable to non-controlling interest
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2020 2019 Change 2020 2019 Change
Net income (loss) attributable to non-controlling interest $ (45) $ 58  $ (103) $ 390  $ 370  $ 20 

Net loss attributable to non-controlling interest increased during the three months ended September 30, 2020 from comparable period in 2019 due to the increase in consolidated net loss recognized by Cheniere Partners, primarily as a result of decreased margins due to (1) lower volumes of LNG sold during the quarter as our SPA customers exercised their rights last quarter to cancel cargoes that were scheduled to be delivered this quarter and (2) fewer cargoes were sold to Cheniere Marketing under agreements with lower margins compared to the comparable period in 2019. Net income attributable to non-controlling interest increased during the nine months ended September 30, 2020 from the nine months ended September 30, 2019 primarily due to an increase in consolidated net income recognized by Cheniere Partners, primarily a result of increased margins due to lower pricing of natural gas feedstock, partially offset by increases in (1) interest expense, net of capitalized interest, (2) loss on modification or extinguishment of debt incurred in conjunction with the refinancing of the 2021 SPL Senior Notes and (3) depreciation and amortization expense.

Off-Balance Sheet Arrangements
 
As of September 30, 2020, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.

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. There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2019.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 1—Nature of Operations and Basis of Presentation of our Notes to Consolidated Financial Statements.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Marketing and Trading Commodity Price Risk

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project, the CCL Project and potential future development of Corpus Christi Stage 3 (“Liquefaction Supply Derivatives”). We have also entered into financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (“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):
September 30, 2020 December 31, 2019
Fair Value Change in Fair Value Fair Value Change in Fair Value
Liquefaction Supply Derivatives $ 521  $ 193  $ 149  $ 179 
LNG Trading Derivatives 92  16  165  22 

54

Interest Rate Risk

We are exposed to interest rate risk primarily when we incur debt related to project financing. Interest rate risk is managed in part by replacing outstanding floating-rate debt with fixed-rate debt with varying maturities. CCH has entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the CCH Credit Facility (“CCH Interest Rate Derivatives”) and to hedge against changes in interest rates that could impact anticipated future issuance of debt by CCH (“CCH Interest Rate Forward Start Derivatives”). In order to test the sensitivity of the fair value of the CCH Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward one-month LIBOR curve across the remaining terms of the CCH Interest Rate Derivatives and CCH Interest Rate Forward Start Derivatives as follows (in millions):
September 30, 2020 December 31, 2019
Fair Value Change in Fair Value Fair Value Change in Fair Value
CCH Interest Rate Derivatives $ (165) $ 1  $ (81) $ 19 
CCH Interest Rate Forward Start Derivatives —  —  (8) 15 

Foreign Currency Exchange Risk

We have entered into foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with operations in countries outside of the United States (“FX Derivatives”). In order to test the sensitivity of the fair value of the FX Derivatives to changes in FX rates, management modeled a 10% change in FX rate between the U.S. dollar and the applicable foreign currencies as follows (in millions):
September 30, 2020 December 31, 2019
Fair Value Change in Fair Value Fair Value Change in Fair Value
FX Derivatives $ 2  $ —  $ 4  $ — 

See Note 6—Derivative Instruments for additional details about our derivative instruments.

ITEM 4.    CONTROLS AND PROCEDURES
 
We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective.
 
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
55


PART II.     OTHER INFORMATION

ITEM 1.    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. There have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2019.

ITEM 1A.    RISK FACTORS
 
There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2019, except for the updates presented in our quarterly report on Form 10-Q for the quarterly period ended March 31, 2020.

ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchases for the three months ended September 30, 2020:
Period Total Number of Shares Purchased (1) Average Price Paid Per Share (2) Total Number of Shares Purchased as a Part of Publicly Announced Plans Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans (3)
July 1 - 31, 2020 43,867 $48.11 — $595,952,809
August 1 - 31, 2020 891 $52.05 — $595,952,809
September 1 - 30, 2020 — $— — $595,952,809
Total
44,758 $48.19 —
(1)Includes issued shares surrendered to us by participants in our share-based compensation plans for payment of applicable tax withholdings on the vesting of share-based compensation awards. Associated shares surrendered by participants are repurchased pursuant to terms of the plan and award agreements and not as part of the publicly announced share repurchase plan.
(2)The price paid per share was based on the average trading price of our common stock on the dates on which we repurchased the shares.
(3)On June 3, 2019, we announced that our Board authorized a 3-year, $1 billion share repurchase program. For additional information, see Note 16—Share Repurchase Program.

56

ITEM 6.    EXHIBITS
Exhibit No. Description
4.1
4.2
4.3
4.4*
10.1
10.2*
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00023 Third Berth Vapor Fence Provisional Sum Scope Removal and Closeout, dated June 22, 2020, (ii) the Change Order CO-00024 Train 6 Thermowell Upgrades, dated June 22, 2020, (iii) the Change Order CO-00025 Third Berth Bubble Curtain, dated June 22, 2020, (iv) the Change Order CO-00026 Third Berth Fuel Provisional Sum Closure Change Order, dated July 14, 2020, (v) the Change Order CO-00027 Third Berth Currency Provisional Sum Closure Change Order, dated July 20, 2020, (vi) the Change Order CO-00028 Train 6 Hot Oil WHRU PSV Bypass, dated August 11, 2020 and (vii) the Change Order CO-00029 Change in Law IMO 2020 Regulatory Change – Low Sulphur Emissions on Marine Vessels, dated August 25, 2020
10.3*
Change orders to the Amended and Restated Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated as of December 12, 2017, between CCL and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00035 Spill Conveyance from Flare KO Drum Area, dated July 6, 2020, (ii) the Change Order CO-00036 Tie-Ins for Heavy Hydrocarbon Removal Modifications (E&P) Rev 1, dated August 5, 2020, (iii) the Change Order CO-00037 Train 3 PV-16002 Valve Trim Change - Rev 1, dated August 14, 2020, (iv) the Change Order CO-00038 Hot Oil Overpressure Relief, dated August 14, 2020, (v) the Change Order CO-00039 Supply of Nitrogen for Commissioning Units 16, 17 and Feed Gas, dated August 20, 2020 and (vi) the Change Order CO-00040 COVID-19 Impacts, dated September 15, 2020 (Portions of this exhibit have been omitted)
31.1*
31.2*
32.1**
32.2**
101.INS* XBRL Instance Document
101.SCH* XBRL Taxonomy Extension Schema Document
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Labels Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document
104* Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
* Filed herewith.
** Furnished herewith.
57


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
CHENIERE ENERGY, INC.
   
Date: November 5, 2020 By: /s/ Zach Davis
Zach Davis
Senior Vice President and Chief Financial Officer
(on behalf of the registrant and
as principal financial officer)
Date: November 5, 2020 By: /s/ Leonard E. Travis
Leonard E. Travis
Senior Vice President and Chief Accounting Officer
  (on behalf of the registrant and
as principal accounting officer)
58

Exhibit 4.4





CHENIERE ENERGY PARTNERS, L.P.,

as Partnership

and

any Subsidiary Guarantors party hereto
and

THE BANK OF NEW YORK MELLON,
as Trustee


FOURTH SUPPLEMENTAL INDENTURE
Dated as of November 5, 2020


Supplement to

the First Supplemental Indenture
Dated as of September 18, 2017
in connection with the 5.250% Senior Notes due 2025,

the Second Supplemental Indenture
Dated as of September 11, 2018
in connection with the 5.625% Senior Notes due 2026

and

the Third Supplemental Indenture
Dated as of September 12, 2019
in connection with the 4.500% Senior Notes due 2029

to

the Indenture Dated as of September 18, 2017



THIS FOURTH SUPPLEMENTAL INDENTURE (this “Fourth Supplemental Indenture”), dated as of November 5, 2020 (the “Effective Date”), is among Cheniere Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), any Subsidiary Guarantors party hereto, and The Bank of New York Mellon, as trustee (the “Trustee”).

RECITALS
WHEREAS, the Partnership and the Subsidiary Guarantors have executed and delivered to the Trustee an Indenture, dated as of September 18, 2017 (the “Base Indenture”), as supplemented by (i) a First Supplemental Indenture, dated as of September 18, 2017 (the “First Supplemental Indenture” and, together with the Base Indenture, the “2025 Notes Indenture”) pursuant to which the Partnership has duly issued 5.250% Senior Notes due 2025 (the “2025 Notes”) in the aggregate principal amount of $1,500,000,000, (ii) a Second Supplemental Indenture, dated as of September 11, 2018 (the “Second Supplemental Indenture” and, together with the Base Indenture, the “2026 Notes Indenture”) pursuant to which the Partnership has duly issued 5.625% Senior Notes due 2026 (the “2026 Notes”) in the aggregate principal amount of $1,100,000,000 and (iii) a Third Supplemental Indenture, dated as of September 12, 2019 (the “Third Supplemental Indenture” and, together with the Base Indenture, the “2029 Notes Indenture”) pursuant to which the Partnership has duly issued 4.500% Senior Notes due 2029 (the “2029 Notes”, and together with the 2025 Notes and the 2026 Notes, the “Notes”) in the aggregate principal amount of $1,500,000,000. The 2025 Notes Indenture, together with the 2026 Notes Indenture and the 2029 Notes Indenture is hereinafter referred to as the “Indentures”.

WHEREAS, (i) pursuant to Section 9.01(a) of the Base Indenture, the Partnership and the Trustee may amend or supplement certain terms of the Indentures or the Notes to cure any ambiguity, omission, defect or inconsistency without the consent of the Holders and (ii) pursuant to Section 9.01(j) of the Base Indenture, the Partnership and the Trustee may amend or supplement certain terms of the Indentures or the Notes to conform the text of the Indentures or the Notes to any provision of the “Description of Notes” contained in the offering memoranda describing the issuances of the Notes;

WHEREAS, the Partnership’s ability to redeem the notes subject to satisfaction of one or more conditions precedent (the “conditional call provision”) contained in the “Description of Notes” of each of (i) the offering memorandum dated September 12, 2017 describing the issuance of the 2025 Notes (the “2025 Description of Notes”), (ii) the offering memorandum dated September 12, 2017 describing the issuance of the 2026 Notes (the “2026 Description of Notes”) and (iii) the offering memorandum dated September 12, 2017 describing the issuance of the 2029 Notes (the “2029 Description of Notes”) was unintentionally omitted from each of the First Supplemental Indenture, the Second Supplemental Indenture and the Third Supplemental Indenture, respectively, and the Partnership desires to enter into this Fourth Supplemental Indenture to supplement each of the First Supplemental Indenture, the Second Supplemental Indenture and the Third Supplemental Indenture (i) to cure any ambiguity and omission as to the Partnership’s ability to redeem the notes subject to satisfaction of one or more conditions precedent; and (ii) to conform the text of each of the First Supplemental Indenture, the Second Supplemental Indenture and the Third Supplemental Indenture to the 2025 Description of Notes,
2

the 2026 Description of Notes and the 2029 Description of Notes, respectively, in each case by adding the conditional call provision;

WHEREAS, pursuant to Section 9.01 of the Base Indenture, the Partnership has requested and hereby requests that the Trustee join in the execution of this Fourth Supplemental Indenture and the Trustee is authorized to execute this Fourth Supplemental Indenture;

WHEREAS, the execution and delivery of this Fourth Supplemental Indenture have been duly authorized by the parties hereto, and all conditions and requirements necessary to make this Fourth Supplemental Indenture a valid and binding agreement of the Partnership and the Subsidiary Guarantors enforceable in accordance with its terms have been duly performed and complied with; and

WHEREAS, the Partnership has heretofore delivered or is delivering contemporaneously herewith to the Trustee (i) a copy of the Board Resolution (as defined in the Base Indenture) authorizing the execution of this Fourth Supplemental Indenture, (ii) the Officers’ Certificate and the Opinion of Counsel described in Sections 9.01, 9.06, 12.04 and 12.05 of the Base Indenture, and (iii) a written request to execute this Fourth Supplemental Indenture.

NOW, THEREFORE, in consideration of the premises, agreements and obligations set for herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree, for the equal and proportionate benefit of all Holders of the Notes, as follows:
3

ARTICLE I
RELATION TO INDENTURE; DEFINITIONS

Section 1.1 Relation to Base Indenture.

With respect to each of the 2025 Notes, the 2026 Notes and the 2029 Notes, this Fourth Supplemental Indenture constitutes an integral part of each of the First Supplemental Indenture, the Second Supplemental Indenture and Third Supplemental Indenture, respectively.

Section 1.2 Generally.

The rules of interpretation set forth in the Indentures shall be applied hereto as if set forth in full herein.

Section 1.3 Definition of Certain Terms.

Capitalized terms used herein and not otherwise defined herein shall have the respective meanings ascribed thereto in the Indentures.

ARTICLE II
AMENDMENTS TO THE INDENTURE

Section 2.1 Effectiveness of Fourth Supplemental Indenture.

This Fourth Supplemental Indenture shall become effective as of the date hereof.

Section 2.2 Amendments to Paragraph 5 of Exhibits A-1 and A-2 of each of the First Supplemental Indenture, the Second Supplemental Indenture and the Third Supplemental Indenture.

(a)The following paragraph shall be added to the end of numbered paragraph 5 in each of Exhibits A-1 and A-2 of the First Supplemental Indenture, the Second Supplemental Indenture and the Third Supplemental Indenture:

“In addition, any redemption pursuant to this paragraph 5 may, at the         Partnership’s discretion, be subject to one or more conditions precedent. If such redemption is subject to the satisfaction of one or more conditions precedent, the related notice shall describe each such condition, and if applicable, shall state that, in the Partnership’s discretion, the redemption date may be delayed until such time as any or all such conditions shall be satisfied or waived (including to a date later than 60 days after the date on which such notice was mailed or delivered electronically), or such redemption may not occur and such notice may be rescinded in the event that any or all such conditions shall not have been satisfied or waived by the redemption date, or by the redemption date as so delayed, or such notice may be rescinded at any time in the Partnership’s discretion if in the good faith judgment of the Partnership any or all of such conditions will not be satisfied or waived.”
4


MISCELLANEOUS PROVISIONS

Section 3.1 Ratification of Indenture.

The Indentures, as supplemented by this Fourth Supplemental Indenture, are in all respects ratified and confirmed, and this Fourth Supplemental Indenture shall be deemed part of each of the First Supplemental Indenture, the Second Supplemental Indenture and Third Supplemental Indenture in the manner and to the extent herein and therein provided.

Section 3.2 Trustee Not Responsible for Recitals.

The recitals and statements contained herein shall be taken as the statements of the Partnership, and the Trustee assumes no responsibility for the correctness of the same. The Trustee makes no representations as to the validity, adequacy or sufficiency of this Fourth Supplemental Indenture.

Section 3.3 Headings.

The headings of the Articles and Sections of this Fourth Supplemental Indenture have been inserted for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

Section 3.4 Counterpart Originals.

This Fourth Supplemental Indenture may be executed in any number of counterparts, each of which shall be an original, but such counterparts shall together constitute but one and the same instrument. The exchange of copies of this Fourth Supplemental Indenture and of signature pages that are executed by manual signatures that are scanned, photocopied or faxed or by other electronic signing created on an electronic platform (such as DocuSign) or by digital signing (such as Adobe Sign), in each case that is approved by the Trustee, shall constitute effective execution and delivery of this Fourth Supplemental Indenture for all purposes. Signatures of the parties hereto that are executed by manual signatures that are scanned, photocopied or faxed or by other electronic signing created on an electronic platform (such as DocuSign) or by digital signing (such as Adobe Sign), in each case that is approved by the Trustee, shall be deemed to be their original signatures for all purposes of this Fourth Supplemental Indenture as to the parties hereto and may be used in lieu of the original.

Anything in this Fourth Supplemental Indenture to the contrary notwithstanding, for the purposes of the transactions contemplated by this Fourth Supplemental Indenture and any document to be signed in connection with the Indentures or this Fourth Supplemental Indenture (including amendments, waivers, consents and other modifications, Officer’s Certificates, Partnership Orders and Opinions of Counsel and other issuance, authentication and delivery documents) or the transactions contemplated hereby may be signed by manual signatures that are scanned, photocopied or faxed or other electronic signatures created on an electronic platform (such as DocuSign) or by digital signature (such as Adobe Sign), in each case that is approved by the Trustee, and contract formations on electronic platforms approved by the Trustee, and the keeping of records in electronic form, are hereby authorized, and each shall be of the same legal
5

effect, validity or enforceability as a manually executed signature in ink or the use of a paper-based recordkeeping system, as the case may be.

Section 3.5 Severability.

In case any provision in this Fourth Supplemental Indenture shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.

Section 3.6 Successors and Assigns.

This Fourth Supplemental Indenture shall inure to the benefit of and be binding upon the parties hereto and each of their respective successors and permitted assigns. Without limiting the generality of the foregoing, this Fourth Supplemental Indenture shall inure to benefit of all Holders from time to time. Nothing expressed or mentioned in this Fourth Supplemental Indenture is intended to or shall be construed to give any Person, other than the parties hereto, their respective successor and assigns, and the Holders, any legal or equitable right, remedy or claim under or in respect of this Fourth Supplemental Indenture or any provision herein contained.

Section 3.7 Governing Law.

THIS FOURTH SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.
Section 3.7 Trust Indenture Act Controls.

Upon registration of any of the Notes in accordance with a Registration Rights Agreement, if any provision of this Fourth Supplemental Indenture limits, qualifies, or conflicts with another provision that is required to be included in any of the Indentures related to such Note by the TIA, the required provision shall control.

[signature pages follow]
6


IN WITNESS WHEREOF, the parties hereto have caused this Fourth Supplemental Indenture to be duly executed as of the day and year first above written.

CHENIERE ENERGY PARTNERS, L.P.
By its general partner, CHENIERE ENERGY
PARTNERS GP, LLC
/s/ Zach Davis
Name: Zach Davis
Title:
Senior Vice President and Chief
Financial Officer
CHENIERE ENERGY INVESTMENTS, LLC
/s/ Zach Davis
Name: Zach Davis
Title:
President and Chief Financial Officer
SABINE PASS LNG-GP, LLC
/s/ Zach Davis
Name: Zach Davis
Title:
Chief Financial Officer
SABINE PASS LNG, L.P.
By its general partner, SABINE PASS LNG-
GP, LLC
/s/ Zach Davis
Name: Zach Davis
Title:
Chief Financial Officer
[SIGNATURE PAGE TO FOURTH SUPPLEMENTAL INDENTURE]

SABINE PASS TUG SERVICES, LLC
/s/ Zach Davis
Name: Zach Davis
Title:
Chief Financial Officer
CHENIERE PIPELINE GP INTERESTS, LLC
/s/ Zach Davis
Name: Zach Davis
Title:
President and Chief Financial Officer
CHENIERE CREOLE TRAIL PIPELINE, L.P.
/s/ Zach Davis
Name: Zach Davis
Title:
Chief Financial Officer

[SIGNATURE PAGE TO FOURTH SUPPLEMENTAL INDENTURE]

THE BANK OF NEW YORK MELLON,
as Trustee
/s/ Francine J. Kincaid
Name: Francine J. Kincaid
Title:
Vice President
[SIGNATURE PAGE TO FOURTH SUPPLEMENTAL INDENTURE]

Exhibit 10.2
CHANGE ORDER
Third Berth Vapor Fence Provisional Sum Scope Removal and Closeout
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00023

DATE OF CHANGE ORDER: June 22, 2020

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order removes the Vapor Fence Provisional Sum from Contractor’s Scope of Work as defined in Section 2.7 of Attachment EE-4 (Provisional Sums to be Adjusted during Project Execution for Subproject 6(b)) of the Agreement.

2.The original value of the Vapor Fence Provisional Sum specified in Article 2.7 of Schedule EE-4 of Attachment EE of the Agreement was Fifteen Million, Eight Hundred Sixty-One Thousand U.S. Dollars (U.S. $15,861,000). Actual costs for the Vapor Fence Provisional Sum was Zero U.S. Dollars (U.S. $0.00). By way of this Change Order, the Vapor Fence Provisional Sum and Contract Price will be decreased by Sixteen Million, Eight Hundred Twelve Thousand, Six Hundred Sixty U.S. Dollars (U.S. $16,812,660), which reflects the closure of the Vapor Fence Provisional Sum and credit for the six percent (6%) fee.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit A of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#00001-00008, 00010-00013, 00015, 00017-00018, and 00021-00022) $ (17,997,214)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,998,895,359 
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 1,998,895,359 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#00014, 00016, and 00019-00020) $ 20,551,502 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 478,247,502 
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order................... $ — 
11. The Provisional Sum Applicable to Subproject 6(b) will be decreased by this Change Order................ $ (16,812,660)
12. The new Contract Price Applicable to Subproject 6(b) including this Change Order will be................... $ 461,434,842 


Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,477,142,861 
15. The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, 10 and 11)......... $ (16,812,660)
16. The new Contract Price including this Change Order will be (add lines 14 and 15) $ 2,460,330,201 

Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): N/A
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit A
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.




/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP E&C Sr Project Manager, PVP
Title Title
June 24, 2020 June 22, 2020
Date of Signing Date of Signing



CHANGE ORDER
Train 6 Thermowell Upgrades
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00024

DATE OF CHANGE ORDER: June 22, 2020

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor’s engineering and procurement costs to upgrade seventy-eight (78) Thermowells for Train 6 to accommodate an increased design flow of 861 MMSCFD in accordance with the recommendations of the debottlenecking study.

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18 & 21-22) $ (17,997,214)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,998,895,359 
4. The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of.................................................................................................................................................... $ 205,198 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 1,999,100,557 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20 & 23) $ 3,738,842 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 461,434,842 
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order................... $ — 
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order................ $ — 
12. The new Contract Price Applicable to Subproject 6(b) including this Change Order will be................... $ 461,434,842 
Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,460,330,201 
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11) $ 205,198 
16. The new Contract Price including this Change Order will be (add lines 14 and 15)................................ $ 2,460,535,399 



Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified : N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): Yes; see Exhibit B
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A
Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): N/A
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials:
/s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP E&C Sr Project Mgr, PVP
Title Title
June 24, 2020 June 22, 2020
Date of Signing Date of Signing



CHANGE ORDER
Third Berth Bubble Curtain
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00025

DATE OF CHANGE ORDER: June 22, 2020

The Agreement between the Parties listed above is changed as follows:
1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor’s engineering, procurement and construction costs to install a bubble curtain to mitigate noise levels during the marine steel piling program. Contractor is unable to quantify or guarantee the level of dBA reduction.

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, & 24)) $ (17,792,016)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,999,100,557 
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of ................ $ — 
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 1,999,100,557 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was................................................................ $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20 & 23) $ 3,738,842 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 461,434,842 
10. The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order $ 2,991,140 
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order $ — 
12. The new Contract Price Applicable to Subproject 6(b) including this Change Order will be $ 464,425,982 
Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,460,535,399 
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11) $ 2,991,140 
16. The new Contract Price including this Change Order will be (add lines 14 and 15)................................ $ 2,463,526,539 


Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): N/A
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A
Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner
Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP E&C Sr Project Mgr, PVP
Title Title
June 24, 2020 June 22, 2020
Date of Signing Date of Signing



CHANGE ORDER
Third Berth Fuel Provisional Sum Closure Change Order
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00026

DATE OF CHANGE ORDER: July 14, 2020

The Agreement between the Parties listed above is changed as follows:
1.The Fuel Provisional Sum in Article 1.2 of Attachment EE, Schedule EE-3 of the Agreement prior to this Change Order was One Million, Five Hundred Seventy-Eight Thousand, Seventy-Four U.S. Dollars (U.S. $1,578,074). The Provisional Sum is hereby decreased by Three Hundred Fourteen Thousand, Five Hundred Seventy-Four U.S. Dollars (U.S. $314,574), and the final value as amended by this Change Order shall be One Million, Two Hundred Sixty-Three Thousand, Five Hundred U.S. Dollars (U.S. $1,263,500). This Change Order closes the Fuel Provisional Sum for Subproject 6(b) in accordance with Article 1.2 of Attachment EE, Schedule EE-3 of the Agreement.

2.Pursuant to instructions in Article 1.2 of Attachment EE, Schedule EE-3 of the Agreement, Exhibit A to this Change Order illustrates the calculation of the final fuel costs in the Agreement with respect to Subproject 6(b).

3.Schedules C-1 and C-2 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestones listed in Exhibit B of this Change Order.

4.Additionally, Exhibit C of this Change Order supersedes the Exhibit B (Payment Milestones Schedule) of Change Order No. 00020 to correct Milestone No. “TB2.02c020” to “TB3.01c020” in accordance with Schedule C-3 (Milestone Payment Schedule for Subproject 6(b)) of Attachment C of the Agreement.
Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, & 24) $ (17,792,016)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,999,100,557 
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 1,999,100,557 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23 & 25) $ 6,729,982 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 464,425,982 
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order................... $ — 
11. The Provisional Sum Applicable to Subproject 6(b) will be decreased by this Change Order................ $ (314,574)
12. The new Contract Price Applicable to Subproject 6(b) including this Change Order will be................... $ 464,111,408 


Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,463,526,539 
15. The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, 10 and 11) $ (314,574)
16. The new Contract Price including this Change Order will be (add lines 14 and 15)................................ $ 2,463,211,965 
Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): N/A
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A
Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B and Exhibit C
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner
Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.


/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP E&C Sr Project Mgr, PVP
Title Title
July 23, 2020 July 14, 2020
Date of Signing Date of Signing



CHANGE ORDER
Third Berth Currency Provisional Sum Closure Change Order
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00027

DATE OF CHANGE ORDER: July 20, 2020

The Agreement between the Parties listed above is changed as follows:
1.The Currency Provisional Sum in Article 1.1 of Attachment EE, Schedule EE-3 of the Agreement prior to this Change Order was Seven Million, One Hundred Seventy-Five Thousand, One Hundred Ninety-Six U.S. Dollars (U.S. $7,175,196). The Provisional Sum is hereby decreased by Three Hundred Three Thousand, Nine Hundred Fifty-Five U.S. Dollars (U.S. $303,955), and the final value as amended by this Change Order shall be Six Million, Eight Hundred Seventy-One Thousand, Two Hundred Forty-One U.S. Dollars (U.S. $6,871,241). This Change Order closes the Currency Provisional Sum for Subproject 6(b) in accordance with Article 1.1 of Attachment EE, Schedule EE-3 of the Agreement.

2.Pursuant to instructions in Article 1.1 of Attachment EE, Schedule EE-3 of the Agreement, Exhibit A to this Change Order illustrates the calculation of the final currency costs in the Agreement with respect to Subproject 6(b).

3.Exhibit C of this Change Order includes the detailed spot and forward trades used to calculate the final currency costs in the Agreement with respect to Subproject 6(b).

4.Schedules C-1 and C-2 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestones listed in Exhibit B of this Change Order.
Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, & 24) $ (17,792,016)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,999,100,557 
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 1,999,100,557 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, & 25-26) $ 6,415,408 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 464,111,408 
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order................... $ — 
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order................ $ (303,955)
12. The new Contract Price Applicable to Subproject 6(b) including this Change Order will be................... $ 463,807,453 


Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,463,211,965 
15. The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, 10 and 11) $ (303,955)
16. The new Contract Price including this Change Order will be (add lines 14 and 15)................................ $ 2,462,908,010 
Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): N/A
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner
Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.



/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP E&C Sr Project Mgr, PVP
Title Title
July 30, 2020 July 20, 2020
Date of Signing Date of Signing



CHANGE ORDER

Train 6 Hot Oil WHRU PSV Bypass
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00028

DATE OF CHANGE ORDER: August 11, 2020

The Agreement between the Parties listed above is changed as follows:
1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor’s engineering, procurement and construction services to actuate the PSV bypass valves and automate their operation based on pressure measurements as reflected in the draft P&ID markups in Exhibit C of this Change Order, and based on the following Scope of Work:

1.1This Change Order is based on valve failure position being FO. Any other failure position other than FO is specifically excluded from this Change Order.

1.2Existing orbit manual valve on thermal oxidizer WHRU (VA-342263) is required to be in open position prior to installation of actuator. The ball valves on the ethylene WHRUs (VA-340198, VA-340113) can be in closed position (subject to confirmation during detailed design). Stroking of the valves will be required to confirm proper actuator operation during the installation phase.

1.3Existing orbit manual valve on thermal oxidizer WHRU (VA-342263) needs to be rotated 45 deg to accommodate clash-free installation of actuator, based on preliminary vendor data.

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.
Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, & 24) $ (17,792,016)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,999,100,557 
4. The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of.................................................................................................................................................... $ 231,381 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
6. The new Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 1,999,331,938 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, & 25-27) $ 6,111,453 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 463,807,453 
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order................... $ — 
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order................ $ — 
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be................... $ 463,807,453 


Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,462,908,010 
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11) $ 231,381 
16. The new Contract Price including this Change Order will be (add lines 14 and 15)................................ $ 2,463,139,391 
Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): Yes; see Exhibit B
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A
Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): N/A
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner
Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.



/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP E&C Sr Project Mgr, PVP
Title Title
August 24, 2020 August 11, 2020
Date of Signing Date of Signing



CHANGE ORDER

Change in Law IMO 2020 Regulatory Change – Low Sulphur Emissions on Marine Vessels
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00029

DATE OF CHANGE ORDER: August 25, 2020

The Agreement between the Parties listed above is changed as follows:
1.In accordance with Section 6.2 of the Agreement (Change Orders Requested by Contractor), the Parties agree this Change Order includes Contractor’s incurred costs as a result of the Change in Law – International Maritime Organization ("IMO") enforcement of a new 0.5% global Sulphur cap on all shipping vessels effective January 1, 2020.

2.The summary cost breakdown for this Change Order is provided in Exhibit A of this Change Order.

3.The detailed cost breakdown for this Change Order is provided in Exhibit C of this Change Order.

4.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.
Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, & 28) $ (17,560,635)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,999,331,938 
4. The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of.................................................................................................................................................... $ 718,581 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
6. The new Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 2,000,050,519 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, & 25-27) $ 6,111,453 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 463,807,453 
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order................... $ — 
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order................ $ — 
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be................... $ 463,807,453 
Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,463,139,391 
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11) $ 718,581 
16. The new Contract Price including this Change Order will be (add lines 14 and 15)................................ $ 2,463,857,972 


Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): Yes; see Exhibit B
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A
Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): N/A
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner
Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP, Engineering and Construction Sr Project Mgr, PVP
Title Title
August 26, 2020 August 25, 2020
Date of Signing Date of Signing



Exhibit 10.3
[***] indicates certain identified information has been excluded because it is both (a) not material and (b) would be competitively harmful if publicly disclosed.
CHANGE ORDER
Spill Conveyance from Flare KO Drum Area
PROJECT NAME: Corpus Christi Stage 2 Liquefaction Facility

OWNER: Corpus Christi Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: December 12, 2017
CHANGE ORDER NUMBER: 00035

DATE OF CHANGE ORDER: July 6, 2020

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1.Pursuant to Article 6.1 of the Agreement (Change Orders Requested by Owner), Parties agree this Change Order includes Contractor’s engineering, procurement and construction costs to add an earthern berm in proximity to the Flare Knock Drums - 00V-1902B, 00V-1901A and 00V-1902A. The Flare K.O. Drums are normally empty of liquids or could potentially contain a very small volume of hazardous liquid. As a result, only minor spillage through flanges, pipeline fittings, or seals are expected and is the basis of the design. However, in order to address FERC’s concern that the location and slope of existing gradient could have the potential to convey spills to the south side swale, a minimum 6-inch earthen berm will be designed and installed to collect and contain minor leaks of hazardous liquids upon accidental releases, and to direct such spills to the northern trench leading to the LNG impoundment basin.

2.The summary cost breakdown of this Change Order is detailed in Exhibit 1 of this Change Order.

3.The detailed cost breakdown of this Change Order is provided in Exhibit 3 of this Change Order.

4.Schedules C-1 and C-3 (Milestone Payment Schedules) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 of this Change Order.

5.The Design Basis in the Agreement is not changed by this Change Order.

6.The Work in this Change Order may not support the CCL Stage 2 construction installation schedule; therefore, completion of the additional Work under this Change Order shall not be a condition precedent to Contractor achieving Substantial Completion and Final Completion of the CCL Stage 2 EPC Agreement.

Adjustment to Contract Price
The original Contract Price was......................................................................................................................... $ 2,360,000,000 
Net change by previously authorized Change Orders (00001-00034)............................................................... $ 46,284,073 
The Contract Price prior to this Change Order was........................................................................................... $ 2,406,284,073 
The Aggregate Equipment Price will be changed by this Change Order in the amount of............................... $ [***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of...................... $ [***]
The new Contract Price including this Change Order will be........................................................................... $ 2,406,531,240 
Adjustment to Aggregate Equipment Price
The original Aggregate Equipment Price was................................................................................................... $ [***]
Net change by previously authorized Change Orders (00001-00034)............................................................... $ [***]
The Aggregate Equipment Price prior to this Change Order was...................................................................... $ [***]
The Aggregate Equipment Price will be changed by this Change Order in the amount of............................... $ [***]
The new Aggregate Equipment Price including this Change Order will be ..................................................... $ [***]


Adjustment to Aggregate Labor and Skills Price
The original Aggregate Labor and Skills Price was.......................................................................................... $ [***]
Net change by previously authorized Change Orders (00001-00034)............................................................... $ [***]
The Aggregate Labor and Skills Price prior to this Change Order was............................................................. $ [***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of...................... $ [***]
The new Aggregate Labor and Skills Price including this Change Order will be............................................. $ [***]
Adjustment to Aggregate Provisional Sum
The original Aggregate Provisional Sum was.................................................................................................... $ 295,549,906 
Net change by previously authorized Change Orders (00001-00034)............................................................... $ (15,701,306)
The Aggregate Provisional Sum prior to this Change Order was...................................................................... $ 279,848,600 
The Aggregate Provisional Sum will be changed by this Change Order in the amount of............................... $ — 
The new Aggregate Provisional Sum including this Change Order will be...................................................... $ 279,848,600 

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule: Yes. See Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: No

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials:
/s/ BT Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.




/s/ David Craft /s/ Bhupesh Thakkar
Owner Contractor
David Craft Bhupesh Thakkar
Name Name
SVP, Engineering and Construction Cheniere Program Manager
Title Title
July 14, 2020 July 8, 2020
Date of Signing Date of Signing


CHANGE ORDER
Tie-Ins for Heavy Hydrocarbon Removal Modifications (E&P) Rev 1
PROJECT NAME: Corpus Christi Stage 2 Liquefaction Facility

OWNER: Corpus Christi Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: December 12, 2017
CHANGE ORDER NUMBER: 00036

DATE OF CHANGE ORDER: August 5, 2020

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1.Pursuant to Article 6.1 of the Agreement (Change Orders Requested by Owner), and Owner Correspondence No. CCLIQ2-BE-C20-026, Parties agree this Change Order includes Contractor’s engineering and procurement costs to facilitate tie-ins for heavy hydrocarbon removal modifications during Phase 1 of the Work as follows:

•Detailed engineering for all fifteen (15) HRU/HHC tie-ins (twelve (12) HHC tie-ins and three (3) HRU tie-ins associated with E-1503).
•Procurement for three (3) HRU tie-ins associated with E-1503. Procurement for the twelve (12) HHC tie-ins is excluded from this Change Order.

2.This Change Order is limited to engineering and procurements costs only as described in Section 1. Construction, balance of Procurement and all Subcontract costs are specifically excluded from this Change Order and subject to a separate Change Order / Agreement per Owner’s direction.

3.The summary cost breakdown of this Change Order is detailed in Exhibit 1 of this Change Order.

4.The detailed cost breakdown of this Change Order is provided in Exhibit 3 of this Change Order.

5.Schedules C-1 and C-3 (Milestone Payment Schedules) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 of this Change Order.

6.The Design Basis in the Agreement is not changed by this Change Order. The seven (7) redlined engineering piping and instrumentation diagrams (P&ID’s) are provided in Exhibit 4 of this Change Order.

7.The Work in this Change Order does not impact the CCL Stage 2 construction installation schedule. The completion of the additional Work under this Change Order shall not be a condition precedent to Contractor achieving Substantial Completion and Final Completion of the CCL Stage 2 EPC Agreement.
Adjustment to Contract Price
The original Contract Price was......................................................................................................................... $ 2,360,000,000 
Net change by previously authorized Change Orders (00001-00035)............................................................... $ 46,531,240 
The Contract Price prior to this Change Order was........................................................................................... $ 2,406,531,240 
The Aggregate Equipment Price will be changed by this Change Order in the amount of............................... $ [***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of...................... $ [***]
The new Contract Price including this Change Order will be........................................................................... $ 2,406,627,759 
Adjustment to Aggregate Equipment Price
The original Aggregate Equipment Price was................................................................................................... $ [***]
Net change by previously authorized Change Orders (00001-00035)............................................................... $ [***]
The Aggregate Equipment Price prior to this Change Order was...................................................................... $ [***]
The Aggregate Equipment Price will be changed by this Change Order in the amount of............................... $ [***]
The new Aggregate Equipment Price including this Change Order will be ..................................................... $ [***]


Adjustment to Aggregate Labor and Skills Price
The original Aggregate Labor and Skills Price was.......................................................................................... $ [***]
Net change by previously authorized Change Orders (00001-00035)............................................................... $ [***]
The Aggregate Labor and Skills Price prior to this Change Order was............................................................. $ [***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of...................... $ [***]
The new Aggregate Labor and Skills Price including this Change Order will be............................................. $ [***]
Adjustment to Aggregate Provisional Sum
The original Aggregate Provisional Sum was.................................................................................................... $ 295,549,906 
Net change by previously authorized Change Orders (00001-00035)............................................................... $ (15,701,306)
The Aggregate Provisional Sum prior to this Change Order was...................................................................... $ 279,848,600 
The Aggregate Provisional Sum will be changed by this Change Order in the amount of............................... $ — 
The new Aggregate Provisional Sum including this Change Order will be...................................................... $ 279,848,600 

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule: Yes. See Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: No

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ BT Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.



/s/ David Craft /s/ Bhupesh Thakkar
Owner Contractor
David Craft Bhupesh Thakkar
Name Name
SVP, E&C Cheniere Program Manager
Title Title
August 14, 2020 August 6, 2020
Date of Signing Date of Signing


CHANGE ORDER
Train 3 PV-16002 Valve Trim Change - Rev 1
PROJECT NAME: Corpus Christi Stage 2 Liquefaction Facility

OWNER: Corpus Christi Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: December 12, 2017
CHANGE ORDER NUMBER: 00037

DATE OF CHANGE ORDER: August 14, 2020

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1.Pursuant to Article 6.1 of the Agreement (Change Orders Requested by Owner), Parties agree this Change Order includes Contractor’s engineering, procurement and construction costs to change the trim on 23PV-16002 valve in Train 3 (per the scope described below). The scope of services included in this Change Order are as follows:

i.Engineering support for replacement of new vendor prints (provided by Owner) into the Train 3 vendor data books, and review of test results.
ii.Disassembly of 23PV-16002 valve and transportation to CCI workshop.
iii.Coordination with CCI to disassemble, install and test upgraded trim (by Owner) at CCI workshop.
iv.Transportation of valve back to the Site and re-installation of the valve in Train 3.
v.To support the schedule, Owner has agreed to furnish Contractor with the Train 2 upgraded trim for the 23PV-16002 valve for use in Train 3 by August 15, 2020, which is currently located at the CCI workshop reserved for future planned Train 2 outage.

2.The summary cost breakdown of this Change Order is detailed in Exhibit 1 of this Change Order.

3.The detailed cost breakdown of this Change Order is provided in Exhibit 3 of this Change Order.

4.Schedules C-1 and C-3 (Milestone Payment Schedules) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 of this Change Order.

Adjustment to Contract Price
The original Contract Price was......................................................................................................................... $ 2,360,000,000 
Net change by previously authorized Change Orders (00001-00036)............................................................... $ 46,627,759 
The Contract Price prior to this Change Order was........................................................................................... $ 2,406,627,759 
The Aggregate Equipment Price will be changed by this Change Order in the amount of............................... $ [***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of...................... $ [***]
The new Contract Price including this Change Order will be........................................................................... $ 2,406,697,584 
Adjustment to Aggregate Equipment Price
The original Aggregate Equipment Price was................................................................................................... $ [***]
Net change by previously authorized Change Orders (00001-00036)............................................................... $ [***]
The Aggregate Equipment Price prior to this Change Order was...................................................................... $ [***]
The Aggregate Equipment Price will be changed by this Change Order in the amount of............................... $ [***]
The new Aggregate Equipment Price including this Change Order will be ..................................................... $ [***]


Adjustment to Aggregate Labor and Skills Price
The original Aggregate Labor and Skills Price was.......................................................................................... $ [***]
Net change by previously authorized Change Orders (00001-00036)............................................................... $ [***]
The Aggregate Labor and Skills Price prior to this Change Order was............................................................. $ [***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of...................... $ [***]
The new Aggregate Labor and Skills Price including this Change Order will be............................................. $ [***]
Adjustment to Aggregate Provisional Sum
The original Aggregate Provisional Sum was.................................................................................................... $ 295,549,906 
Net change by previously authorized Change Orders (00001-00036)............................................................... $ (15,701,306)
The Aggregate Provisional Sum prior to this Change Order was...................................................................... $ 279,848,600 
The Aggregate Provisional Sum will be changed by this Change Order in the amount of............................... $ — 
The new Aggregate Provisional Sum including this Change Order will be...................................................... $ 279,848,600 

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule: Yes. See Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: No

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ BT Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.



/s/ David Craft /s/ Bhupesh Thakkar
Owner Contractor
David Craft Bhupesh Thakkar
Name Name
SVP, Engineering and Construction Cheniere Program Manager
Title Title
August 28, 2020 August 14, 2020
Date of Signing Date of Signing


CHANGE ORDER
Hot Oil Overpressure Relief
PROJECT NAME: Corpus Christi Stage 2 Liquefaction Facility

OWNER: Corpus Christi Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: December 12, 2017
CHANGE ORDER NUMBER: 00038

DATE OF CHANGE ORDER: August 14, 2020

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1.Pursuant to Article 6.1 of the Agreement (Change Orders Requested by Owner), Parties agree this Change Order includes Contractor’s engineering, procurement and construction costs to actuate the PSV bypass valves and automate their operation based on pressure measurements (“Hot Oil Overpressure Relief”) as reflected in Design Change Notice (DECN) No. 25959-100-M6N-DK-00101, dated 23 June 2020.

The scope of services included in this Change Order are as follows:

i.Engineering, procurement and construction costs to install one (1) new orbit actuator for Thermal Oxidizer WHRU (VA-342263), and two (2) new actuators for Ethylene WHRU’s (VA-340198 and VA-340113).
ii.This Change Order is based on valve failure position being Fail Open (FO). Any failure position other than FO is excluded from this Change Order.
iii.Existing orbit manual valve on Thermal Oxidizer WHRU (VA-342263) is required to be in open position prior to installation of actuator. The ball valves on the Ethylene WHRU’s (VA-340198, VA-340113) can be in closed position (subject to confirmation during detailed design). Stroking of the valves will be required to confirm proper actuator operation during the installation phase.
iv.Existing orbit manual valve on Thermal Oxidizer WHRU (VA-342263) needs to be rotated 45 degrees to accommodate clash-free installation of actuator based on preliminary vendor data. The rotation of this valve has already been completed on Train 3. Any changes or modifications by the Vendor during detailed design has a potential to impact fit-up, and the installation strategy which is excluded from this Change Order.
v.This Change Order excludes resolution of any action item(s) arising from HAZOP.
vi.The estimated lead time for delivery of the actuators for this Change Order is as follows:
i.32-34 weeks for new orbit actuator for Thermal Oxidizer WHRU (VA-342263)
ii.12-14 weeks for new actuators for Ethylene WHRU’s (VA-340198 and VA-340113)
vii.Owner to provide access to Contractor to perform installation after receipt of materials, which will be coordinated in advance.

2.The summary cost breakdown of this Change Order is detailed in Exhibit 1 of this Change Order.

3.The detailed cost breakdown of this Change Order is provided in Exhibit 3 of this Change Order.

4.Schedules C-1 and C-3 (Milestone Payment Schedules) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 of this Change Order.

5.The Work in this Change Order may not support the CCL Stage 2 construction installation schedule due to estimated lead time of the actuators; therefore, completion of the additional Work under this Change Order shall not be a condition precedent to Contractor achieving Substantial Completion and Final Completion of the CCL Stage 2 EPC Agreement.

6.The Design Basis in the Agreement is not changed by this Change Order.


Adjustment to Contract Price
The original Contract Price was......................................................................................................................... $ 2,360,000,000 
Net change by previously authorized Change Orders (00001-00037)............................................................... $ 46,697,584 
The Contract Price prior to this Change Order was........................................................................................... $ 2,406,697,584 
The Aggregate Equipment Price will be changed by this Change Order in the amount of............................... $ [***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of...................... $ [***]
The new Contract Price including this Change Order will be........................................................................... $ 2,406,934,288 
Adjustment to Aggregate Equipment Price
The original Aggregate Equipment Price was................................................................................................... $ [***]
Net change by previously authorized Change Orders (00001-00037)............................................................... $ [***]
The Aggregate Equipment Price prior to this Change Order was...................................................................... $ [***]
The Aggregate Equipment Price will be changed by this Change Order in the amount of............................... $ [***]
The new Aggregate Equipment Price including this Change Order will be ..................................................... $ [***]
Adjustment to Aggregate Labor and Skills Price
The original Aggregate Labor and Skills Price was.......................................................................................... $ [***]
Net change by previously authorized Change Orders (00001-00037)............................................................... $ [***]
The Aggregate Labor and Skills Price prior to this Change Order was............................................................. $ [***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of...................... $ [***]
The new Aggregate Labor and Skills Price including this Change Order will be............................................. $ [***]
Adjustment to Aggregate Provisional Sum
The original Aggregate Provisional Sum was.................................................................................................... $ 295,549,906 
Net change by previously authorized Change Orders (00001-00037)............................................................... $ (15,701,306)
The Aggregate Provisional Sum prior to this Change Order was...................................................................... $ 279,848,600 
The Aggregate Provisional Sum will be changed by this Change Order in the amount of............................... $ — 
The new Aggregate Provisional Sum including this Change Order will be...................................................... $ 279,848,600 

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule: Yes. See Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: No

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ BT Contractor /s/ DC Owner



[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft /s/ Bhupesh Thakkar
Owner Contractor
David Craft Bhupesh Thakkar
Name Name
SVP, Engineering & Construction Cheniere Program Manager
Title Title
September 3, 2020 August 14, 2020
Date of Signing Date of Signing



CHANGE ORDER

Supply of Nitrogen for Commissioning Units 16, 17 and Feed Gas
PROJECT NAME: Corpus Christi Stage 2 Liquefaction Facility

OWNER: Corpus Christi Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: December 12, 2017
CHANGE ORDER NUMBER: 00039

DATE OF CHANGE ORDER: August 20, 2020

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1.Pursuant to Article 6.2 of the Agreement (Change Orders Requested by Contractor), Parties agree this Change Order includes Contractor’s estimated supply of nitrogen for Subproject 3 (Train 3) Commissioning activities (dryout and defrosting of Units 16, 17 and Feed Gas). This Change Order is based on the approved Trend No. S2-0074. Upon completion of the Commissioning activities requiring the supply of nitrogen for this Change Order, Contractor shall true-up actual costs for supply of nitrogen (with backup invoices) and provide a separate Change Order for Owner’s review and approval.

i.If the actual supply of nitrogen costs is less than the amount of this Change Order, Owner shall be entitled to a Change Order under the Agreement reducing the Contract Price by such difference.

ii.If the actual supply of nitrogen costs is greater than the amount of this Change Order, Contractor shall be entitled to a Change Order under the Agreement increasing the Contract Price by such difference.

2.The summary cost breakdown of this Change Order is detailed in Exhibit 1 of this Change Order.

3.The detailed cost breakdown of this Change Order is provided in Exhibit 3 of this Change Order.

4.Schedules C-1 and C-3 (Milestone Payment Schedules) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 of this Change Order.
Adjustment to Contract Price
The original Contract Price was......................................................................................................................... $ 2,360,000,000 
Net change by previously authorized Change Orders (00001-00038)............................................................... $ 46,934,288 
The Contract Price prior to this Change Order was........................................................................................... $ 2,406,934,288 
The Aggregate Equipment Price will be changed by this Change Order in the amount of............................... $ [***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of...................... $ [***]
The new Contract Price including this Change Order will be........................................................................... $ 2,409,111,104 
Adjustment to Aggregate Equipment Price
The original Aggregate Equipment Price was................................................................................................... $ [***]
Net change by previously authorized Change Orders (00001-00038)............................................................... $ [***]
The Aggregate Equipment Price prior to this Change Order was...................................................................... $ [***]
The Aggregate Equipment Price will be changed by this Change Order in the amount of............................... $ [***]
The new Aggregate Equipment Price including this Change Order will be ..................................................... $ [***]


Adjustment to Aggregate Labor and Skills Price
The original Aggregate Labor and Skills Price was.......................................................................................... $ [***]
Net change by previously authorized Change Orders (00001-00038)............................................................... $ [***]
The Aggregate Labor and Skills Price prior to this Change Order was............................................................. $ [***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of...................... $ [***]
The new Aggregate Labor and Skills Price including this Change Order will be............................................. $ [***]
Adjustment to Aggregate Provisional Sum
The original Aggregate Provisional Sum was.................................................................................................... $ 295,549,906 
Net change by previously authorized Change Orders (00001-00038)............................................................... $ (15,701,306)
The Aggregate Provisional Sum prior to this Change Order was...................................................................... $ 279,848,600 
The Aggregate Provisional Sum will be changed by this Change Order in the amount of............................... $ — 
The new Aggregate Provisional Sum including this Change Order will be...................................................... $ 279,848,600 

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule: Yes. See Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: No

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ BT Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.



/s/ David Craft /s/ Bhupesh Thakkar
Owner Contractor
David Craft Bhupesh Thakkar
Name Name
SVP, Engineering & Construction Cheniere Program Manager
Title Title
September 4, 2020 August 20, 2020
Date of Signing Date of Signing



CHANGE ORDER

COVID-19 Impacts
PROJECT NAME: Corpus Christi Stage 2 Liquefaction Facility

OWNER: Corpus Christi Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: December 12, 2017
CHANGE ORDER NUMBER: 00040

DATE OF CHANGE ORDER: September 15, 2020

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1.Pursuant to Article 6.2 of the Agreement (Change Orders Requested by Contractor), Parties agree this Change Order includes Contractor’s actual costs incurred from March 2020 through July 2020 and forecasted costs from August 2020 through December 2020, both in response to the novel coronavirus (COVID-19) outbreak event.

This Change Order is based on the following assumptions and qualifications through the end of December 2020:

i.Contractor’s Houston home office personnel have worked and shall continue working effectively remotely until such time the office is safe to re-open according to federal, state and local government officials’ orders and Bechtel policies.

ii.Contractor has been able to keep the Jobsite open throughout the event and shall continue doing so, to the extent reasonably possible, to advance the Work at the current rate of progress (or better if possible), with no planned shutdown in 2020.

iii.Contractor shall continue to put forth diligent mitigation efforts to minimize impacts caused by the event to the extent reasonably practical, including but not limited to: increased craft professional hours for additional cleaning, disinfecting, etc.; increased bussing services to support social distancing; additional cleaning stations, waste management services, etc.; quarantine requirements for supplier technical support (international and others); continued COVID-19 testing costs and hours (excluding quarantine time); increased professional staff for contact tracing efforts and backup support for CSU organization; and additional safety PPE, communication materials (e.g., posters, signs).

iv.No major COVID-19 infection outbreak on the Jobsite resulting in: (i) Site shutdown of all or critical scopes of the Work; or (ii) absenteeism at or above the twenty percent (20%) level for a sustained duration of more than four (4) Weeks. Should either of these triggers occur, the Parties shall jointly collaborate on mitigation actions and plans for shutdown accordingly.

v.Existing government (local, state and/or federal) guidelines, executive orders, actions or directives as of 31 July 2020 shall remain unchanged through the end of December 2020. New government orders shall be subject to separate notices and Change Orders, if applicable.

vi.Owner’s operations and other professional staff personnel shall continue to support the CSU activities for the Project in support of the Work.

vii.Subcontractors and Suppliers shall continue to provide uninterrupted support for construction and commissioning activities either at Site or remotely if possible.

viii.Any changes in the above assumptions and qualifications and additional costs beyond 2020 are excluded from this Change Order; and may be part of a separate Change Order in accordance with Article 6.2 of the Agreement.

2.Contractor has not experienced schedule impacts on the critical path of the CPM Schedule through 31 July 2020; and should all the qualifications and assumptions above remain as stated, Contractor does not anticipate any schedule impacts to the Project on the critical path of the CPM Schedule through the end of December 2020. In the event of the occurrence of any impacts to the critical path of the CPM Schedule, Contractor shall notify Owner in accordance with Article 6.5 of the Agreement.

3.The summary cost breakdown of this Change Order is detailed in Exhibit 1 of this Change Order.



4.The detailed cost breakdown of this Change Order is provided in Exhibit 3 of this Change Order.

5.Schedules C-1 and C-3 (Milestone Payment Schedules) of Attachment C of the Agreement will be amended by including the Milestones listed in Exhibit 2 of this Change Order.
Adjustment to Contract Price
The original Contract Price was......................................................................................................................... $ 2,360,000,000 
Net change by previously authorized Change Orders (00001-00039)............................................................... $ 49,111,104 
The Contract Price prior to this Change Order was........................................................................................... $ 2,409,111,104 
The Aggregate Equipment Price will be changed by this Change Order in the amount of............................... $ [***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of...................... $ [***]
The new Contract Price including this Change Order will be........................................................................... $ 2,416,774,972 
Adjustment to Aggregate Equipment Price
The original Aggregate Equipment Price was................................................................................................... $ [***]
Net change by previously authorized Change Orders (00001-00039)............................................................... $ [***]
The Aggregate Equipment Price prior to this Change Order was...................................................................... $ [***]
The Aggregate Equipment Price will be changed by this Change Order in the amount of............................... $ [***]
The new Aggregate Equipment Price including this Change Order will be ..................................................... $ [***]
Adjustment to Aggregate Labor and Skills Price
The original Aggregate Labor and Skills Price was.......................................................................................... $ [***]
Net change by previously authorized Change Orders (00001-00039)............................................................... $ [***]
The Aggregate Labor and Skills Price prior to this Change Order was............................................................. $ [***]
The Aggregate Labor and Skills Price will be changed by this Change Order in the amount of...................... $ [***]
The new Aggregate Labor and Skills Price including this Change Order will be............................................. $ [***]
Adjustment to Aggregate Provisional Sum
The original Aggregate Provisional Sum was.................................................................................................... $ 295,549,906 
Net change by previously authorized Change Orders (00001-00039)............................................................... $ (15,701,306)
The Aggregate Provisional Sum prior to this Change Order was...................................................................... $ 279,848,600 
The Aggregate Provisional Sum will be changed by this Change Order in the amount of............................... $ — 
The new Aggregate Provisional Sum including this Change Order will be...................................................... $ 279,848,600 

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): See Item No. 2 above.

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule: Yes. See Exhibit 2 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: No

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A



Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ BT Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft /s/ Bhupesh Thakkar
Owner Contractor
David Craft Bhupesh Thakkar
Name Name
SVP, Engineering & Construction Cheniere Program Manager
Title Title
September 30, 2020 September 15, 2020
Date of Signing Date of Signing


Exhibit 31.1
CERTIFICATION BY CHIEF EXECUTIVE OFFICER
PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT
I, Jack A. Fusco, certify that:
1.    I have reviewed this quarterly report on Form 10-Q of Cheniere Energy, Inc.;
2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.    The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)     Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)     Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
d)     Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.     The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)     All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)     Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2020 
/s/ Jack A. Fusco
Jack A. Fusco
Chief Executive Officer of
Cheniere Energy, Inc.



Exhibit 31.2
CERTIFICATION BY CHIEF FINANCIAL OFFICER
PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT
I, Zach Davis, certify that:
1.    I have reviewed this quarterly report on Form 10-Q of Cheniere Energy, Inc.;
2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.     The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)     Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)     Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)     Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
d)     Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.     The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)     All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)     Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2020
/s/ Zach Davis
Zach Davis
Chief Financial Officer of
Cheniere Energy, Inc.



Exhibit 32.1
CERTIFICATION BY CHIEF EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the quarterly report of Cheniere Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended September 30, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:
(1)    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 5, 2020 
/s/ Jack A. Fusco
Jack A. Fusco
Chief Executive Officer of
Cheniere Energy, Inc.



Exhibit 32.2
CERTIFICATION BY CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the quarterly report of Cheniere Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended September 30, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Zach Davis, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:
(1)    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 5, 2020 
/s/ Zach Davis
Zach Davis
Chief Financial Officer of
Cheniere Energy, Inc.