8152119131214415255173662047722275182369224710325113529301116301011273121383220214103330215113410211235321311033151011203416620130311724218102104Other (Specify) (footnote details)193202204Other (Define) (footnote details)4207304215310310562320320524743058251045927204810611285206122910530630131320510714316163071511069716220610831773084181076981952072086208109523108109624208209Other (Specify) (footnote details)579309861091210Other (Define) (footnote details)97111107582091031091110172101010121072111201111121112211131113102122111121431225285055224282101286056225281129705722628111129805822728211306232911213010612312921231306223229131314063233291133250642342921313260652352914337066236291141338067237292143478233015134107241301153530712423021513550722433016260732443011610280752453021620286247301730210872431117402308824131217502408252311860250812533111870260822553121880270832563119902808425321193952513221910310962523220203309725332120303409825432220403509265322150360912663212160370922673222170380932633228031042613312290311052623323431062633312310451082643322320461027533243047101276331245048102277332560411327341257041115271342258043116272341904411727334101551182753421056112863410220571112873433058112283544051232813556424112435234125355126356127351626712436812536241363611373635134378613537713637813737114438114538951463861473881443921553938115639205157396151715101381520116301341162516102716202581631710317Dates: FEBRUARY 18-20, 201915117203Date: FEBRUARY 19, 201975173038171046182041185351810581820521305712162322110617321206421752110796212076572187482110822208122910Other (Specify) (footnote details)222109Other (Define) (footnote details)322209242211011182713O13141815641713633Other Clearing (Specify) (footnote details):181919FalseOriginal value: N192521EESWS29ESSGSS15LG-A14LNG138LSS7S-2SS-229WSSOther391136139202331167312211630370114715521622144128361028321241376736672235925101214161815245681122121311321361411421415115821516116216179117217181181910119201202112112221222312324131241425125222612615271272812829171293013031231311932132331333420212103152413412203162615312417283513104181135113519336213105204103136215371141062261372147237383141074248148225911510812610215912711315109528121510729141611093013161183122161119323171210334117112123652171341131711352218146331181148443181510552181151266191625771191165883191716992191172710102018471111201185612222019581333201196514422120115512112021662221127122121248222223693221224710232359111231236111222424712133241248C0006541424259151412412510161525261118161251261219172252713211812756 C000654 0-16 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 ScheduleUnamortizedLossAndGainOnReacquiredDebtAbstract 2018-01-01 2018-12-31 C000654 ferc:MayMember 2018-01-01 2018-12-31 C000654 3-3 2017-01-01 2017-12-31 C000654 1-21 2018-01-01 2018-12-31 C000654 2-34 2018-01-01 2018-12-31 C000654 1-24 2018-01-01 2018-12-31 C000654 1-12 2018-01-01 2018-12-31 C000654 1-34 2017-12-31 C000654 2-33 2018-01-01 2018-12-31 C000654 0-23 2018-01-01 2018-12-31 C000654 2018-12-31 C000654 0-33 ferc:GasUtilityMember 2018-12-31 C000654 1-15 2017-01-01 2017-12-31 C000654 0-2 2018-12-31 C000654 0-19 2017-12-31 C000654 1-8 2018-01-01 2018-12-31 C000654 6-36 2018-01-01 2018-12-31 C000654 0-24 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-35 2018-01-01 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 3-8 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-3 0-3 2018-01-01 2018-12-31 C000654 3-11 2018-01-01 2018-12-31 C000654 1-19 2018-01-01 2018-12-31 C000654 0-35 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-25 2018-12-31 C000654 4-35 2018-01-01 2018-12-31 C000654 6-10 2018-01-01 2018-12-31 C000654 0-11 2018-12-31 C000654 0-32 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 3-9 2018-01-01 2018-12-31 C000654 1-12 2017-01-01 2017-12-31 C000654 1-29 2018-01-01 2018-12-31 C000654 1-26 2018-01-01 2018-12-31 C000654 0-24 2018-01-01 2018-12-31 C000654 0-5 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 2-9 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 2-8 2018-01-01 2018-12-31 C000654 ferc:NegotiatedRateMember 2018-11-01 2018-11-30 C000654 7-27 2018-01-01 2018-12-31 C000654 1-5 2018-12-31 C000654 1-5 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 2-12 2018-01-01 2018-12-31 C000654 3-32 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-4 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 5-14 2018-01-01 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 2-14 2018-01-01 2018-12-31 C000654 0-10 2017-01-01 2017-12-31 C000654 ferc:ThreeDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 5-31 2018-01-01 2018-12-31 C000654 0-66 2018-11-01 2018-11-30 C000654 0-2 2018-01-01 2018-12-31 C000654 4-22 2018-01-01 2018-12-31 C000654 ferc:CreditedMember 2018-12-01 2018-12-31 C000654 2-27 2018-01-01 2018-12-31 C000654 0-21 2018-01-01 2018-12-31 C000654 0-26 2018-01-01 2018-12-31 C000654 0-23 2018-01-01 2018-12-31 C000654 1-21 2018-01-01 2018-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 0-4 2018-12-31 C000654 3-26 2018-01-01 2018-12-31 C000654 2-2 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-5 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 2-11 2017-01-01 2017-12-31 C000654 ferc:DeliveredToInterstatePipelinesMember ferc:ThreeDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 0-64 2018-01-01 2018-12-31 C000654 3-21 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 7-9 2018-01-01 2018-12-31 C000654 0-30 2018-01-01 2018-12-31 C000654 0-32 ferc:GasUtilityMember 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 8-6 2018-01-01 2018-12-31 C000654 6-11 2018-01-01 2018-12-31 C000654 7-4 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-13 2017-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 7-38 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 0-1 2018-12-31 C000654 1-1 2018-12-31 C000654 0-68 2018-10-01 2018-10-31 C000654 4-33 2018-01-01 2018-12-31 C000654 1-18 2017-12-31 C000654 4-38 2018-01-01 2018-12-31 C000654 0-29 2018-01-01 2018-12-31 C000654 1-15 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 3-2 2017-01-01 2017-12-31 C000654 2-4 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-8 0-8 2018-01-01 2018-12-31 C000654 2-20 2018-01-01 2018-12-31 C000654 0-29 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-2 2018-01-01 2018-12-31 C000654 0-23 2018-01-01 2018-12-31 C000654 0-22 2018-01-01 2018-12-31 C000654 3-13 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-19 2018-01-01 2018-12-31 C000654 2-3 2017-12-31 C000654 0-25 2018-01-01 2018-12-31 C000654 0-19 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-2 2018-12-31 C000654 0-17 ferc:GasUtilityMember 2018-12-31 C000654 1-11 2018-01-01 2018-12-31 C000654 ferc:OtherStoragePlantMember ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 5-33 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-6 2018-12-31 C000654 0-17 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 3-16 2017-01-01 2017-12-31 C000654 1-28 2018-12-31 C000654 1-32 2018-12-31 C000654 1-32 2017-12-31 C000654 1-7 2018-01-01 2018-12-31 C000654 1-34 2018-01-01 2018-12-31 C000654 3-17 2017-01-01 2017-12-31 C000654 3-23 2018-01-01 2018-12-31 C000654 0-38 2018-01-01 2018-12-31 C000654 1-7 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-33 2018-01-01 2018-12-31 C000654 0-16 2017-01-01 2017-12-31 C000654 2-18 2018-01-01 2018-12-31 C000654 6-37 2018-01-01 2018-12-31 C000654 0-1 2018-12-31 C000654 1-5 2018-01-01 2018-12-31 C000654 3-19 2017-01-01 2017-12-31 C000654 ScheduleInvestmentsAbstract 2018-01-01 2018-12-31 C000654 0-69 2018-11-01 2018-11-30 C000654 0-23 2018-01-01 2018-12-31 C000654 0-12 2018-12-31 C000654 3-8 2017-01-01 2017-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-32 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-11 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 2-4 2018-01-01 2018-12-31 C000654 0-72 2018-11-01 2018-11-30 C000654 0-22 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 2-3 2018-01-01 2018-12-31 C000654 0-26 2018-01-01 2018-12-31 C000654 0-6 ferc:SingleDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 2-32 2018-01-01 2018-12-31 C000654 0-10 ferc:GasUtilityMember 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 1-24 2018-01-01 2018-12-31 C000654 3-28 2018-01-01 2018-12-31 C000654 0-14 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 ferc:SingleDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 1-4 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 5-39 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 1-22 ferc:OtherUtilityMember 2018-01-01 2018-12-31 C000654 ferc:AllocationOfPayrollChargedForClearingAccountsMember 2018-01-01 2018-12-31 C000654 0-12 2018-12-31 C000654 0-14 0-14 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 8-5 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-5 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 0-6 2018-11-01 2018-11-30 C000654 8-26 2018-01-01 2018-12-31 C000654 4-12 2018-01-01 2018-12-31 C000654 0-37 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-19 2018-01-01 2018-12-31 C000654 6-24 2018-01-01 2018-12-31 C000654 1-4 2018-01-01 2018-12-31 C000654 0-8 2018-12-31 C000654 ferc:OperatingUtilityMember 2018-01-01 2018-12-31 C000654 0-14 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 0-75 2018-01-01 2018-12-31 C000654 2-30 2018-01-01 2018-12-31 C000654 0-22 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 1-7 2018-12-31 C000654 0-7 2017-01-01 2017-12-31 C000654 2-25 2017-01-01 2017-12-31 C000654 1-21 2018-01-01 2018-12-31 C000654 0-7 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 7-2 2018-01-01 2018-12-31 C000654 2-12 2018-12-31 C000654 2-20 2018-01-01 2018-12-31 C000654 1-22 2018-01-01 2018-12-31 C000654 0-69 2018-01-01 2018-12-31 C000654 2-14 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 3-1 2017-01-01 2017-12-31 C000654 2-10 2018-01-01 2018-12-31 C000654 8-17 2018-01-01 2018-12-31 C000654 0-21 2018-01-01 2018-12-31 C000654 0-16 2018-12-31 C000654 1-2 2018-01-01 2018-12-31 C000654 0-25 ferc:DeliveredToInterstatePipelinesMember ferc:ThreeDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 3-24 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-3 2017-01-01 2017-12-31 C000654 3-10 2017-01-01 2017-12-31 C000654 2-14 2018-01-01 2018-12-31 C000654 1-36 2017-12-31 C000654 0-36 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 2-24 2018-01-01 2018-12-31 C000654 0-27 2018-01-01 2018-12-31 C000654 0-15 2018-12-31 C000654 0-66 2018-12-01 2018-12-31 C000654 4-25 2018-01-01 2018-12-31 C000654 1-25 2018-12-31 C000654 1-13 2017-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-30 2018-01-01 2018-12-31 C000654 0-19 2018-01-01 2018-12-31 C000654 1-29 2018-12-31 C000654 8-2 2018-01-01 2018-12-31 C000654 0-15 2018-12-31 C000654 0-32 2018-01-01 2018-12-31 C000654 3-5 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-2 ferc:GasUtilityMember 2018-12-31 C000654 0-31 2018-01-01 2018-12-31 C000654 0-6 ferc:DeliveredToInterstatePipelinesMember ferc:SingleDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-27 2018-01-01 2018-12-31 C000654 0-8 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-3 2018-12-31 C000654 1-28 2018-01-01 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 0-1 2017-01-01 2017-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 3-15 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 6-26 2018-01-01 2018-12-31 C000654 0-9 2018-12-31 C000654 0-32 2018-01-01 2018-12-31 C000654 1-8 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 1-20 2018-01-01 2018-12-31 C000654 ferc:DeliveredToOthersMember ferc:ThreeDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 2-13 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-5 2018-01-01 2018-12-31 C000654 0-18 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 0-5 2018-12-31 C000654 1-5 2018-01-01 2018-12-31 C000654 0-25 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 2-23 2018-01-01 2018-12-31 C000654 0-17 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 3-34 2018-01-01 2018-12-31 C000654 ferc:CreditedMember 2018-10-01 2018-10-31 C000654 0-20 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 0-6 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 3-13 2017-01-01 2017-12-31 C000654 2-22 2017-01-01 2017-12-31 C000654 0-5 0-5 2017-12-31 C000654 0-5 2017-01-01 2017-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-31 2018-01-01 2018-12-31 C000654 2-16 2017-01-01 2017-12-31 C000654 0-23 2018-12-31 C000654 0-6 ferc:GasUtilityMember 2018-12-31 C000654 0-22 2018-01-01 2018-12-31 C000654 2-6 2018-01-01 2018-12-31 C000654 0-36 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-8 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 5-16 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 1-7 2018-01-01 2018-12-31 C000654 0-71 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 1-26 2018-01-01 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 0-9 2018-11-01 2018-11-30 C000654 2-11 2018-01-01 2018-12-31 C000654 1-9 2018-01-01 2018-12-31 C000654 6-23 2018-01-01 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 3-11 2017-01-01 2017-12-31 C000654 0-25 2018-01-01 2018-12-31 C000654 0-5 2017-01-01 2017-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-15 0-15 2018-01-01 2018-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 0-33 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 6-25 2018-01-01 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 0-17 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 0-23 2018-01-01 2018-12-31 C000654 0-27 2017-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 0-20 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-9 0-9 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 2-24 2017-01-01 2017-12-31 C000654 0-4 2017-01-01 2017-12-31 C000654 0-7 0-7 2018-01-01 2018-12-31 C000654 1-30 2018-01-01 2018-12-31 C000654 0-34 ferc:GasUtilityMember 2018-12-31 C000654 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-1 2018-12-31 C000654 1-18 2018-01-01 2018-12-31 C000654 0-15 ferc:GasUtilityMember 2018-12-31 C000654 0-38 ferc:GasUtilityMember 2018-12-31 C000654 0-17 ferc:SingleDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 0-8 2017-01-01 2017-12-31 C000654 0-10 0-10 2017-12-31 C000654 0-30 2018-01-01 2018-12-31 C000654 1-35 ferc:OtherUtilityMember 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 0-24 2018-01-01 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 3-8 2018-01-01 2018-12-31 C000654 7-33 2018-01-01 2018-12-31 C000654 0-6 ferc:DeliveredToOthersMember ferc:SingleDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 0-4 2017-01-01 2017-12-31 C000654 0-22 2018-01-01 2018-12-31 C000654 0-4 2017-01-01 2017-12-31 C000654 1-1 2018-12-31 C000654 0-10 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-13 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 2-3 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 0-1 ferc:GasUtilityMember 2018-12-31 C000654 0-29 2018-01-01 2018-12-31 C000654 0-12 2017-01-01 2017-12-31 C000654 1-16 2018-01-01 2018-12-31 C000654 6-29 2018-01-01 2018-12-31 C000654 1-26 2017-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 0-2 2017-12-31 C000654 0-24 2018-01-01 2018-12-31 C000654 0-14 2018-12-31 C000654 0-37 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 2-14 2017-01-01 2017-12-31 C000654 1-9 2018-01-01 2018-12-31 C000654 0-7 2018-10-01 2018-10-31 C000654 0-29 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 1-2 2017-01-01 2017-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 0-11 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 2017-12-31 C000654 0-21 2018-01-01 2018-12-31 C000654 5-28 2018-01-01 2018-12-31 C000654 0-3 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-14 2017-12-31 C000654 0-2 2018-12-31 C000654 5-15 2018-01-01 2018-12-31 C000654 0-2 2018-12-31 C000654 5-32 2018-01-01 2018-12-31 C000654 0-10 2017-01-01 2017-12-31 C000654 1-9 2017-01-01 2017-12-31 C000654 0-21 2018-12-31 C000654 ScheduleGasPropertyAndCapacityLeasedToOthersAbstract 2018-01-01 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 0-19 2018-01-01 2018-12-31 C000654 1-25 2017-01-01 2017-12-31 C000654 0-67 2018-12-01 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 0-23 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-26 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-14 2017-12-31 C000654 4-29 2018-01-01 2018-12-31 C000654 3-29 2018-01-01 2018-12-31 C000654 0-3 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-5 2018-12-31 C000654 0-4 2018-12-31 C000654 1-7 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-13 0-13 2017-12-31 C000654 2-10 2018-01-01 2018-12-31 C000654 1-22 2018-01-01 2018-12-31 C000654 0-9 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-7 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-14 ferc:GasUtilityMember 2018-12-31 C000654 4-30 2018-01-01 2018-12-31 C000654 4-2 2018-01-01 2018-12-31 C000654 0-20 2018-01-01 2018-12-31 C000654 0-32 2018-01-01 2018-12-31 C000654 0-20 ferc:GasUtilityMember 2018-12-31 C000654 0-12 2018-12-31 C000654 1-1 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 1-31 2018-01-01 2018-12-31 C000654 3-3 2018-01-01 2018-12-31 C000654 8-9 2018-01-01 2018-12-31 C000654 1-3 2017-01-01 2017-12-31 C000654 1-26 2018-12-31 C000654 ferc:GasUtilityMember 2017-12-31 C000654 0-5 2018-12-31 C000654 0-18 2017-12-31 C000654 0-7 2018-12-31 C000654 0-12 2017-12-31 C000654 2-10 2018-01-01 2018-12-31 C000654 3-30 2018-01-01 2018-12-31 C000654 0-21 2018-12-31 C000654 0-10 0-10 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-24 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-23 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-23 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 6-15 2018-01-01 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 0-6 0-6 2018-12-31 C000654 0-65 2018-11-01 2018-11-30 C000654 1-6 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 2-22 2018-01-01 2018-12-31 C000654 3-25 2018-01-01 2018-12-31 C000654 1-30 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 3-27 2018-01-01 2018-12-31 C000654 9-3 2018-01-01 2018-12-31 C000654 5-10 2018-01-01 2018-12-31 C000654 8-21 2018-01-01 2018-12-31 C000654 0-23 2017-01-01 2017-12-31 C000654 1-30 2017-12-31 C000654 3-2 2018-01-01 2018-12-31 C000654 2018-12-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 ferc:RecourseRateMember 2018-11-01 2018-11-30 C000654 0-16 2018-01-01 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 0-70 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-20 2017-01-01 2017-12-31 C000654 0-37 ferc:GasUtilityMember 2018-12-31 C000654 1-8 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-24 2018-01-01 2018-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 1-13 2017-01-01 2017-12-31 C000654 0-1 2017-12-31 C000654 0-18 2017-01-01 2017-12-31 C000654 1-7 2018-01-01 2018-12-31 C000654 1-7 2017-01-01 2017-12-31 C000654 0-20 2018-01-01 2018-12-31 C000654 ferc:SeptemberMember 2018-01-01 2018-12-31 C000654 6-14 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 1-3 2018-01-01 2018-12-31 C000654 5-27 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 1-36 2018-01-01 2018-12-31 C000654 0-24 2018-12-31 C000654 0-26 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-2 2017-01-01 2017-12-31 C000654 7-34 2018-01-01 2018-12-31 C000654 0-3 2018-12-31 C000654 0-15 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-2 2017-01-01 2017-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 8-3 2018-01-01 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 0-33 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 5-24 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 1-17 2018-01-01 2018-12-31 C000654 1-14 2018-01-01 2018-12-31 C000654 ScheduleTransmissionAndCompressionOfGasByOthersAbstract 2018-01-01 2018-12-31 C000654 1-10 2018-01-01 2018-12-31 C000654 0-47 2018-01-01 2018-12-31 C000654 1-15 2018-01-01 2018-12-31 C000654 ferc:GasPlantInServiceMember ferc:GasUtilityMember 2017-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 3-10 2018-01-01 2018-12-31 C000654 0-2 2018-12-31 C000654 0-20 2018-01-01 2018-12-31 C000654 ferc:ProductionAndGatheringPlantMember ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-64 ferc:NegotiatedRateMember 2018-11-01 2018-11-30 C000654 0-32 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 0-3 2017-01-01 2017-12-31 C000654 1-13 2018-01-01 2018-12-31 C000654 1-38 2018-01-01 2018-12-31 C000654 1-6 2018-01-01 2018-12-31 C000654 0-10 2017-12-31 C000654 0-25 2018-01-01 2018-12-31 C000654 3-4 2018-01-01 2018-12-31 C000654 0-10 0-10 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 1-31 2017-12-31 C000654 0-25 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 4-28 2018-01-01 2018-12-31 C000654 0-29 2018-01-01 2018-12-31 C000654 7-24 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 1-19 2017-01-01 2017-12-31 C000654 0-23 2018-01-01 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 2-2 2017-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 4-36 2018-01-01 2018-12-31 C000654 0-27 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-33 ferc:OtherUtilityMember 2018-01-01 2018-12-31 C000654 1-11 2018-01-01 2018-12-31 C000654 0-21 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-12 2018-12-31 C000654 0-32 2018-01-01 2018-12-31 C000654 1-11 2018-01-01 2018-12-31 C000654 0-23 ferc:GasUtilityMember 2018-12-31 C000654 4-11 2018-01-01 2018-12-31 C000654 0-34 2018-01-01 2018-12-31 C000654 0-23 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-39 2018-01-01 2018-12-31 C000654 1-5 2018-01-01 2018-12-31 C000654 0-6 2018-12-31 C000654 0-13 0-13 2018-01-01 2018-12-31 C000654 0-28 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-6 2018-12-31 C000654 8-18 2018-01-01 2018-12-31 C000654 0-36 ferc:GasUtilityMember 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 1-6 2018-01-01 2018-12-31 C000654 1-17 2017-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 1-13 2018-12-31 C000654 0-19 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 5-26 2018-01-01 2018-12-31 C000654 0-4 2018-12-01 2018-12-31 C000654 0-36 ferc:ThreeDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 0-25 2018-12-31 C000654 8-25 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 6-22 2018-01-01 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 0-21 2018-01-01 2018-12-31 C000654 1-11 2018-01-01 2018-12-31 C000654 0-7 2017-01-01 2017-12-31 C000654 3-24 2017-01-01 2017-12-31 C000654 0-11 2017-12-31 C000654 ferc:PayrollBilledByAffiliatedCompaniesMember 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 0-4 2017-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 1-32 2018-01-01 2018-12-31 C000654 5-2 2018-01-01 2018-12-31 C000654 0-34 2018-01-01 2018-12-31 C000654 3-20 2018-01-01 2018-12-31 C000654 0-16 0-16 2017-12-31 C000654 0-35 ferc:GasUtilityMember 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-27 2018-12-31 C000654 0-65 2018-12-01 2018-12-31 C000654 0-35 2018-01-01 2018-12-31 C000654 1-4 2018-01-01 2018-12-31 C000654 1-14 2018-01-01 2018-12-31 C000654 0-22 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-8 2018-01-01 2018-12-31 C000654 5-29 2018-01-01 2018-12-31 C000654 3-7 2018-01-01 2018-12-31 C000654 2-5 2018-01-01 2018-12-31 C000654 0-17 2018-12-31 C000654 ScheduleExtraordinaryPropertyLossesAbstract 2018-01-01 2018-12-31 C000654 2-8 2018-12-31 C000654 0-25 2017-01-01 2017-12-31 C000654 0-5 2017-01-01 2017-12-31 C000654 1-1 2018-01-01 2018-12-31 C000654 0-28 ferc:GasUtilityMember 2018-12-31 C000654 0-24 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 1-10 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-9 2018-12-01 2018-12-31 C000654 0-39 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract 2018-01-01 2018-12-31 C000654 0-7 ferc:GasUtilityMember 2018-12-31 C000654 1-22 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 1-11 2018-01-01 2018-12-31 C000654 1-13 2018-01-01 2018-12-31 C000654 0-28 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 8-14 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 1-13 2018-01-01 2018-12-31 C000654 2-2 2018-01-01 2018-12-31 C000654 1-17 2018-12-31 C000654 1-35 2018-01-01 2018-12-31 C000654 0-28 2018-01-01 2018-12-31 C000654 0-1 2018-12-31 C000654 1-31 2018-01-01 2018-12-31 C000654 0-19 2018-12-31 C000654 0-3 2017-12-31 C000654 0-19 2018-01-01 2018-12-31 C000654 1-22 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-33 2018-01-01 2018-12-31 C000654 0-1 2018-12-31 C000654 1-8 2017-01-01 2017-12-31 C000654 2-9 2018-01-01 2018-12-31 C000654 6-3 2018-01-01 2018-12-31 C000654 2-4 2018-01-01 2018-12-31 C000654 0-34 2018-01-01 2018-12-31 C000654 0-4 2018-12-31 C000654 0-15 0-15 2017-12-31 C000654 1-22 2018-01-01 2018-12-31 C000654 0-22 2018-01-01 2018-12-31 C000654 1-27 2018-12-31 C000654 0-30 2018-01-01 2018-12-31 C000654 5-4 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 0-30 2018-01-01 2018-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 1-8 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-4 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-12 2018-12-31 C000654 0-1 2018-12-31 C000654 0-9 2017-12-31 C000654 ferc:JuneMember 2018-01-01 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 0-26 2018-12-31 C000654 7-35 2018-01-01 2018-12-31 C000654 1-30 2018-01-01 2018-12-31 C000654 0-21 2018-01-01 2018-12-31 C000654 0-6 2017-01-01 2017-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 0-19 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 2-9 2017-12-31 C000654 0-38 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-2 0-2 2017-12-31 C000654 1-10 2018-01-01 2018-12-31 C000654 0-20 2018-01-01 2018-12-31 C000654 0-4 2018-11-01 2018-11-30 C000654 0-14 2018-12-31 C000654 1-1 2018-01-01 2018-12-31 C000654 6-28 2018-01-01 2018-12-31 C000654 0-19 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-14 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-75 ferc:PayrollBilledByAffiliatedCompaniesMember 2018-01-01 2018-12-31 C000654 0-36 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-12 2018-12-31 C000654 0-6 2018-12-31 C000654 7-30 2018-01-01 2018-12-31 C000654 0-30 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 2-18 2017-01-01 2017-12-31 C000654 1-2 2018-01-01 2018-12-31 C000654 0-30 ferc:GasUtilityMember 2018-12-31 C000654 1-9 2018-01-01 2018-12-31 C000654 ScheduleGasPlantHeldForFutureUseAbstract 2018-01-01 2018-12-31 C000654 0-8 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 7-25 2018-01-01 2018-12-31 C000654 0-11 2018-12-31 C000654 4-21 2018-01-01 2018-12-31 C000654 7-11 2018-01-01 2018-12-31 C000654 2-26 2018-01-01 2018-12-31 C000654 2-15 2017-01-01 2017-12-31 C000654 1-9 2018-01-01 2018-12-31 C000654 1-8 2018-01-01 2018-12-31 C000654 0-25 ferc:GasUtilityMember 2018-12-31 C000654 0-9 0-9 2017-12-31 C000654 0-74 2018-12-01 2018-12-31 C000654 1-1 2018-01-01 2018-12-31 C000654 1-20 2017-01-01 2017-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 1-22 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-56 2018-01-01 2018-12-31 C000654 0-4 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 0-26 2018-01-01 2018-12-31 C000654 5-17 2018-01-01 2018-12-31 C000654 0-8 0-8 2017-12-31 C000654 0-5 0-5 2018-12-31 C000654 2-5 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 ferc:OperatingUtilityMember 2017-12-31 C000654 1-21 2017-01-01 2017-12-31 C000654 5-3 2018-01-01 2018-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 8-15 2018-01-01 2018-12-31 C000654 1-29 2018-01-01 2018-12-31 C000654 0-3 2018-12-01 2018-12-31 C000654 5-37 2018-01-01 2018-12-31 C000654 0-29 ferc:GasUtilityMember 2018-12-31 C000654 7-6 2018-01-01 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 1-1 2018-01-01 2018-12-31 C000654 0-6 0-6 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 0-15 2018-12-31 C000654 2-6 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-5 2017-01-01 2017-12-31 C000654 0-9 0-9 2018-12-31 C000654 0-5 2018-12-01 2018-12-31 C000654 3-17 2018-01-01 2018-12-31 C000654 0-22 2018-01-01 2018-12-31 C000654 0-67 2018-11-01 2018-11-30 C000654 0-17 2018-01-01 2018-12-31 C000654 2-5 2018-01-01 2018-12-31 C000654 0-16 2017-12-31 C000654 0-24 2018-01-01 2018-12-31 C000654 1-27 2018-01-01 2018-12-31 C000654 0-19 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-31 ferc:GasUtilityMember 2018-12-31 C000654 0-6 2017-01-01 2017-12-31 C000654 1-4 2018-01-01 2018-12-31 C000654 1-3 2018-01-01 2018-12-31 C000654 1-22 2017-12-31 C000654 1-3 2018-01-01 2018-12-31 C000654 0-3 2018-12-31 C000654 0-33 2018-01-01 2018-12-31 C000654 0-6 0-6 2017-12-31 C000654 0-12 2017-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-5 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 1-14 2018-01-01 2018-12-31 C000654 0-8 2018-12-31 C000654 0-3 2018-12-31 C000654 2-2 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 1-25 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 6-31 2018-01-01 2018-12-31 C000654 0-8 2018-12-01 2018-12-31 C000654 0-21 2018-01-01 2018-12-31 C000654 1-34 2018-12-31 C000654 0-6 2017-01-01 2017-12-31 C000654 0-1 2017-01-01 2017-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 ScheduleCapitalStockSubscribedLiabilityForConversionPremiumOnAndInstallmentsReceivedOnAbstract 2018-01-01 2018-12-31 C000654 0-9 2018-10-01 2018-10-31 C000654 5-36 2018-01-01 2018-12-31 C000654 1-19 2018-01-01 2018-12-31 C000654 1-16 2018-01-01 2018-12-31 C000654 1-25 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 0-4 2018-12-31 C000654 3-9 2018-01-01 2018-12-31 C000654 2-21 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-12 2017-01-01 2017-12-31 C000654 1-3 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 0-2 2018-12-31 C000654 1-23 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 0-10 2018-12-31 C000654 0-7 2018-12-31 C000654 0-8 2018-12-31 C000654 1-15 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 1-12 2018-01-01 2018-12-31 C000654 0-6 2017-12-31 C000654 2-19 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 7-29 2018-01-01 2018-12-31 C000654 2-3 2018-01-01 2018-12-31 C000654 ferc:GasUtilityMember 2017-01-01 2017-12-31 C000654 0-26 2018-12-31 C000654 2-5 2018-01-01 2018-12-31 C000654 2-21 2017-01-01 2017-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 1-33 2018-01-01 2018-12-31 C000654 2-25 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-12 ferc:GasUtilityMember 2018-12-31 C000654 0-3 2017-01-01 2017-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-10 2018-12-31 C000654 0-11 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-19 2018-01-01 2018-12-31 C000654 7-36 2018-01-01 2018-12-31 C000654 0-29 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-8 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 ferc:OperatingUtilityMember 2018-12-31 C000654 0-22 2018-01-01 2018-12-31 C000654 0-9 2018-12-31 C000654 1-20 2018-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 0-5 ferc:GasUtilityMember 2018-12-31 C000654 2017-01-01 2017-12-31 C000654 0-22 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-21 2018-01-01 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 0-22 2018-01-01 2018-12-31 C000654 2-18 2018-01-01 2018-12-31 C000654 0-64 ferc:RecourseRateMember 2018-11-01 2018-11-30 C000654 1-14 2018-01-01 2018-12-31 C000654 3-22 2017-01-01 2017-12-31 C000654 ferc:IntangiblePlantMember ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 ferc:NovemberMember 2018-01-01 2018-12-31 C000654 5-34 2018-01-01 2018-12-31 C000654 1-28 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-19 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-20 2018-12-31 C000654 3-22 2018-01-01 2018-12-31 C000654 0-26 ferc:GasUtilityMember 2018-12-31 C000654 2-11 2017-12-31 C000654 0-9 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 2-12 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-15 2017-12-31 C000654 1-18 2018-12-31 C000654 5-7 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 1-3 2018-01-01 2018-12-31 C000654 0-2 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 8-13 2018-01-01 2018-12-31 C000654 0-5 2018-11-01 2018-11-30 C000654 4-26 2018-01-01 2018-12-31 C000654 1-21 2018-01-01 2018-12-31 C000654 7-32 2018-01-01 2018-12-31 C000654 ferc:OctoberMember 2018-01-01 2018-12-31 C000654 6-7 2018-01-01 2018-12-31 C000654 2-1 2018-01-01 2018-12-31 C000654 0-9 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-18 2018-12-31 C000654 0-1 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-19 ferc:GasUtilityMember 2018-12-31 C000654 1-35 2018-01-01 2018-12-31 C000654 0-11 0-11 2018-12-31 C000654 1-19 2018-01-01 2018-12-31 C000654 1-12 2018-01-01 2018-12-31 C000654 0-19 2018-01-01 2018-12-31 C000654 0-6 2017-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-6 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-24 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-23 2018-01-01 2018-12-31 C000654 0-8 2017-01-01 2017-12-31 C000654 ferc:AprilMember 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-64 ferc:DiscountedRateMember 2018-11-01 2018-11-30 C000654 0-1 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-14 2017-12-31 C000654 0-16 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-4 2018-12-31 C000654 0-22 2018-12-31 C000654 0-25 2018-01-01 2018-12-31 C000654 1-24 2018-12-31 C000654 3-16 2018-01-01 2018-12-31 C000654 ferc:DebitedMember 2018-12-01 2018-12-31 C000654 ferc:RecourseRateMember 2018-10-01 2018-10-31 C000654 0-28 2018-01-01 2018-12-31 C000654 1-24 2017-01-01 2017-12-31 C000654 3-14 2017-01-01 2017-12-31 C000654 0-25 2018-01-01 2018-12-31 C000654 2-15 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 6-5 2018-01-01 2018-12-31 C000654 0-3 2018-10-01 2018-10-31 C000654 1-2 2018-12-31 C000654 ferc:GasPlantInServiceMember ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 2-3 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-3 0-3 2017-12-31 C000654 3-3 2018-01-01 2018-12-31 C000654 2-29 2018-01-01 2018-12-31 C000654 1-2 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 ferc:JanuaryMember 2018-01-01 2018-12-31 C000654 2-2 2018-12-31 C000654 0-65 2018-01-01 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-29 2018-01-01 2018-12-31 C000654 1-36 2018-12-31 C000654 0-4 2017-12-31 C000654 0-25 2018-01-01 2018-12-31 C000654 1-2 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-21 2017-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 7-12 2018-01-01 2018-12-31 C000654 0-1 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 0-21 2018-01-01 2018-12-31 C000654 0-37 2018-01-01 2018-12-31 C000654 0-24 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 0-31 2018-01-01 2018-12-31 C000654 0-30 2018-01-01 2018-12-31 C000654 0-11 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 ferc:GasUtilityMember 2018-12-31 C000654 2-23 2018-01-01 2018-12-31 C000654 0-64 2018-11-01 2018-11-30 C000654 ScheduleCapitalStockExpenseAbstract 2018-01-01 2018-12-31 C000654 0-1 2017-12-31 C000654 ferc:FebruaryMember 2018-01-01 2018-12-31 C000654 2016-12-31 C000654 0-1 2018-12-31 C000654 3-33 2018-01-01 2018-12-31 C000654 0-32 2018-01-01 2018-12-31 C000654 5-30 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-25 ferc:ThreeDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 0-27 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 2-8 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-11 ferc:GasUtilityMember 2018-12-31 C000654 0-12 ferc:SingleDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 3-12 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 8-24 2018-01-01 2018-12-31 C000654 0-13 ferc:GasUtilityMember 2018-12-31 C000654 0-4 2018-12-31 C000654 5-11 2018-01-01 2018-12-31 C000654 0-3 2018-12-31 C000654 ferc:DeliveredToInterstatePipelinesMember ferc:SingleDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 0-29 2018-12-31 C000654 0-21 ferc:GasUtilityMember 2018-12-31 C000654 1-28 2017-12-31 C000654 1-12 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-24 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 4-6 2018-01-01 2018-12-31 C000654 4-39 2018-01-01 2018-12-31 C000654 1-28 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-4 0-4 2018-12-31 C000654 0-12 0-12 2017-12-31 C000654 0-26 2017-12-31 C000654 0-24 2017-12-31 C000654 5-12 2018-01-01 2018-12-31 C000654 0-35 2018-01-01 2018-12-31 C000654 0-6 2018-12-31 C000654 1-7 2018-01-01 2018-12-31 C000654 0-13 2018-12-31 C000654 0-18 ferc:GasUtilityMember 2018-12-31 C000654 0-20 2018-01-01 2018-12-31 C000654 0-19 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 1-10 2017-01-01 2017-12-31 C000654 0-8 2018-11-01 2018-11-30 C000654 0-5 2018-12-31 C000654 0-69 2018-10-01 2018-10-31 C000654 0-7 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-27 2017-12-31 C000654 3-18 2017-01-01 2017-12-31 C000654 1-2 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-20 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-15 0 2018-01-01 2018-12-31 C000654 2-9 2018-12-31 C000654 0-6 2018-12-31 C000654 ScheduleDiscountOnCapitalStockAbstract 2018-01-01 2018-12-31 C000654 ferc:DebitedMember 2018-10-01 2018-10-31 C000654 0-2 2018-01-01 2018-12-31 C000654 1-25 2018-01-01 2018-12-31 C000654 1-23 2018-01-01 2018-12-31 C000654 0-30 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 1-27 2018-01-01 2018-12-31 C000654 1-6 2018-01-01 2018-12-31 C000654 2-11 2018-01-01 2018-12-31 C000654 0-12 2017-12-31 C000654 0-20 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 2-15 2018-01-01 2018-12-31 C000654 1-17 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 0-10 2018-12-31 C000654 7-10 2018-01-01 2018-12-31 C000654 2-5 2018-01-01 2018-12-31 C000654 2-13 2018-01-01 2018-12-31 C000654 0-22 2018-01-01 2018-12-31 C000654 0-12 0-12 2018-12-31 C000654 0-1 0-1 2018-01-01 2018-12-31 C000654 0-27 2018-01-01 2018-12-31 C000654 2-6 2018-01-01 2018-12-31 C000654 ferc:DecemberMember 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-24 2017-01-01 2017-12-31 C000654 7-23 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-27 2018-01-01 2018-12-31 C000654 2-11 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-12 2017-12-31 C000654 2-12 2017-12-31 C000654 5-5 2018-01-01 2018-12-31 C000654 7-15 2018-01-01 2018-12-31 C000654 ferc:NegotiatedRateMember 2018-10-01 2018-10-31 C000654 0-5 2018-10-01 2018-10-31 C000654 2-3 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-5 2017-01-01 2017-12-31 C000654 2-19 2018-01-01 2018-12-31 C000654 2-9 2017-01-01 2017-12-31 C000654 6-21 2018-01-01 2018-12-31 C000654 0-33 2018-01-01 2018-12-31 C000654 6-33 2018-01-01 2018-12-31 C000654 2-1 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-7 2018-12-31 C000654 ferc:JulyMember 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 6-12 2018-01-01 2018-12-31 C000654 0-39 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 ferc:AugustMember 2018-01-01 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 0-13 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 2-3 2018-01-01 2018-12-31 C000654 0-27 2018-01-01 2018-12-31 C000654 1-29 2018-01-01 2018-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 1-10 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 7-8 2018-01-01 2018-12-31 C000654 0-1 0-1 2017-12-31 C000654 3-9 2017-01-01 2017-12-31 C000654 0-18 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-16 2018-12-31 C000654 0-25 2018-01-01 2018-12-31 C000654 0-9 2017-01-01 2017-12-31 C000654 0-21 2018-01-01 2018-12-31 C000654 1-17 2018-01-01 2018-12-31 C000654 1-39 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 7-13 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 2-8 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0 2018-01-01 2018-12-31 C000654 0-7 2018-12-31 C000654 1-6 2018-01-01 2018-12-31 C000654 0-26 2018-01-01 2018-12-31 C000654 0-22 2017-01-01 2017-12-31 C000654 3-20 2017-01-01 2017-12-31 C000654 0-29 2018-01-01 2018-12-31 C000654 0-11 0-11 2017-12-31 C000654 0-7 2017-01-01 2017-12-31 C000654 1-25 2018-01-01 2018-12-31 C000654 0-15 2017-01-01 2017-12-31 C000654 0-17 2017-01-01 2017-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-16 2018-12-31 C000654 2-3 2018-01-01 2018-12-31 C000654 3-4 2017-01-01 2017-12-31 C000654 0-26 2018-01-01 2018-12-31 C000654 3-11 2018-01-01 2018-12-31 C000654 2-5 2017-01-01 2017-12-31 C000654 1-15 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 0-73 2018-01-01 2018-12-31 C000654 2-17 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 ferc:UndergroundGasStoragePlantMember ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-34 2018-01-01 2018-12-31 C000654 2-1 2018-01-01 2018-12-31 C000654 0-20 2018-01-01 2018-12-31 C000654 0-31 2018-01-01 2018-12-31 C000654 1-11 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-9 2018-12-31 C000654 6-32 2018-01-01 2018-12-31 C000654 0-3 2018-11-01 2018-11-30 C000654 0-3 ferc:GasUtilityMember 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 0-71 2018-12-01 2018-12-31 C000654 2-3 2017-01-01 2017-12-31 C000654 0-5 2018-12-31 C000654 5-8 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 0-2 0-2 2018-01-01 2018-12-31 C000654 0-72 2018-01-01 2018-12-31 C000654 1-4 2018-01-01 2018-12-31 C000654 0-38 2018-01-01 2018-12-31 C000654 0-17 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 2-4 2018-01-01 2018-12-31 C000654 1-23 2018-01-01 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 0-27 2018-01-01 2018-12-31 C000654 2-21 2018-01-01 2018-12-31 C000654 1-14 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 2-25 2018-01-01 2018-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 1-32 2018-01-01 2018-12-31 C000654 0-12 2018-12-31 C000654 0-30 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-23 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 2-17 2017-01-01 2017-12-31 C000654 0-11 0-11 2018-01-01 2018-12-31 C000654 1-24 2018-01-01 2018-12-31 C000654 9-4 2018-01-01 2018-12-31 C000654 0-28 2018-01-01 2018-12-31 C000654 0-2 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 2018-11-01 2018-11-30 C000654 4-37 2018-01-01 2018-12-31 C000654 1-29 2017-12-31 C000654 0-73 2018-10-01 2018-10-31 C000654 2018-10-01 2018-10-31 C000654 0-24 ferc:GasUtilityMember 2018-12-31 C000654 2-16 2018-01-01 2018-12-31 C000654 1-14 2018-01-01 2018-12-31 C000654 7-39 2018-01-01 2018-12-31 C000654 0-12 0-12 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 3-24 2018-01-01 2018-12-31 C000654 2-16 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-66 2018-10-01 2018-10-31 C000654 0-24 2018-01-01 2018-12-31 C000654 0-9 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 5-22 2018-01-01 2018-12-31 C000654 1-24 2018-01-01 2018-12-31 C000654 0-2 2017-12-31 C000654 1-31 2018-01-01 2018-12-31 C000654 0-8 ferc:GasUtilityMember 2018-12-31 C000654 3-5 2017-01-01 2017-12-31 C000654 0-25 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-2 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-74 2018-10-01 2018-10-31 C000654 0-21 2018-12-31 C000654 1-16 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-74 2018-11-01 2018-11-30 C000654 6-35 2018-01-01 2018-12-31 C000654 2-25 2018-01-01 2018-12-31 C000654 0-5 0-5 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 6-4 2018-01-01 2018-12-31 C000654 0-17 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-36 2018-01-01 2018-12-31 C000654 0-16 0-16 2018-01-01 2018-12-31 C000654 0-18 2018-12-31 C000654 2-2 2017-01-01 2017-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 0-13 2017-01-01 2017-12-31 C000654 0-71 2018-11-01 2018-11-30 C000654 7-37 2018-01-01 2018-12-31 C000654 8-23 2018-01-01 2018-12-31 C000654 ferc:NegotiatedRateMember 2018-12-01 2018-12-31 C000654 6-27 2018-01-01 2018-12-31 C000654 6-6 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 1-18 2018-01-01 2018-12-31 C000654 1-36 ferc:OtherUtilityMember 2018-01-01 2018-12-31 C000654 4-5 2018-01-01 2018-12-31 C000654 7-5 2018-01-01 2018-12-31 C000654 1-38 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-23 2017-12-31 C000654 0-23 2018-01-01 2018-12-31 C000654 2-22 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 7-16 2018-01-01 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 3-22 2018-01-01 2018-12-31 C000654 1-4 2017-01-01 2017-12-31 C000654 0-13 2018-12-31 C000654 1-13 2018-01-01 2018-12-31 C000654 1-22 2017-01-01 2017-12-31 C000654 9-2 2018-01-01 2018-12-31 C000654 0-6 2018-10-01 2018-10-31 C000654 0-21 2018-01-01 2018-12-31 C000654 0-4 ferc:GasUtilityMember 2018-12-31 C000654 0-9 ferc:GasUtilityMember 2018-12-31 C000654 0-23 2018-01-01 2018-12-31 C000654 0-30 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 0-8 0-8 2018-12-31 C000654 1-36 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-10 2018-01-01 2018-12-31 C000654 0-20 2018-01-01 2018-12-31 C000654 1-21 2018-01-01 2018-12-31 C000654 6-34 2018-01-01 2018-12-31 C000654 0-6 2018-12-31 C000654 0-20 2018-01-01 2018-12-31 C000654 2-17 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-10 2018-12-31 C000654 0-5 2017-12-31 C000654 0-68 2018-11-01 2018-11-30 C000654 3-19 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 2-11 2018-01-01 2018-12-31 C000654 0-14 2017-01-01 2017-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 0-6 2017-12-31 C000654 0-7 2018-12-01 2018-12-31 C000654 0-3 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-28 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 2-8 2018-01-01 2018-12-31 C000654 0-25 2018-01-01 2018-12-31 C000654 0-16 2018-12-31 C000654 0-32 2018-01-01 2018-12-31 C000654 0-23 2018-12-31 C000654 2-6 2018-01-01 2018-12-31 C000654 2-5 2017-12-31 C000654 0-30 2018-01-01 2018-12-31 C000654 0-22 2018-12-31 C000654 0-34 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-72 2018-12-01 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 2-12 2018-01-01 2018-12-31 C000654 0-31 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 3-3 2018-01-01 2018-12-31 C000654 1-1 2017-01-01 2017-12-31 C000654 2-1 2018-01-01 2018-12-31 C000654 6-13 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 0-2 0-2 2018-12-31 C000654 0-34 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 1-9 2018-01-01 2018-12-31 C000654 0-24 2018-01-01 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 8-22 2018-01-01 2018-12-31 C000654 ferc:DeliveredToOthersMember ferc:SingleDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 0-31 2018-12-31 C000654 3-7 2017-01-01 2017-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-35 2018-01-01 2018-12-31 C000654 3-2 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 0-38 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-28 2018-01-01 2018-12-31 C000654 2-28 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0 2018-10-01 2018-12-31 C000654 0-8 2018-10-01 2018-10-31 C000654 1-13 2018-01-01 2018-12-31 C000654 2-10 2017-01-01 2017-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 ferc:DiscountedRateMember 2018-11-01 2018-11-30 C000654 0-18 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 1-18 2017-01-01 2017-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-73 2018-12-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 1-12 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 3-18 2018-01-01 2018-12-31 C000654 1-1 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-22 2018-01-01 2018-12-31 C000654 0-4 2018-10-01 2018-10-31 C000654 0-10 2018-12-31 C000654 0-9 2017-12-31 C000654 ferc:DebitedMember 2018-11-01 2018-11-30 C000654 0-2 2018-01-01 2018-12-31 C000654 0-25 2018-01-01 2018-12-31 C000654 0-36 2018-01-01 2018-12-31 C000654 7-22 2018-01-01 2018-12-31 C000654 6-2 2018-01-01 2018-12-31 C000654 1-38 2017-12-31 C000654 8-16 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-3 2018-12-31 C000654 0-22 ferc:GasUtilityMember 2018-12-31 C000654 1-2 2018-01-01 2018-12-31 C000654 0-29 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 1-5 2018-01-01 2018-12-31 C000654 0-19 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 2-10 2018-12-31 C000654 1-17 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-36 2018-01-01 2018-12-31 C000654 8-27 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-35 2018-01-01 2018-12-31 C000654 1-9 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-56 2017-01-01 2017-12-31 C000654 ScheduleCapitalStockAbstract 2018-01-01 2018-12-31 C000654 2-24 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 1-38 2018-12-31 C000654 0-27 2018-01-01 2018-12-31 C000654 0-7 2018-11-01 2018-11-30 C000654 0-13 2018-01-01 2018-12-31 C000654 3-1 2018-01-01 2018-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 0-37 2018-01-01 2018-12-31 C000654 0-73 2018-11-01 2018-11-30 C000654 6-38 2018-01-01 2018-12-31 C000654 0-4 0-4 2018-01-01 2018-12-31 C000654 2-10 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 ferc:TransmissionPlantMember ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-69 2018-12-01 2018-12-31 C000654 0-70 2018-11-01 2018-11-30 C000654 ferc:OtherUtilityMember 2018-01-01 2018-12-31 C000654 7-3 2018-01-01 2018-12-31 C000654 0-35 2018-12-31 C000654 2-6 2017-01-01 2017-12-31 C000654 5-9 2018-01-01 2018-12-31 C000654 0-24 2018-01-01 2018-12-31 C000654 1-20 2017-12-31 C000654 3-6 2018-01-01 2018-12-31 C000654 3-4 2018-01-01 2018-12-31 C000654 1-25 2018-01-01 2018-12-31 C000654 0-68 2018-12-01 2018-12-31 C000654 0-4 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 5-21 2018-01-01 2018-12-31 C000654 ferc:DiscountedRateMember 2018-10-01 2018-10-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-7 0-7 2017-12-31 C000654 0-65 2018-10-01 2018-10-31 C000654 ferc:GeneralPlantMember ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-17 ferc:DeliveredToOthersMember ferc:SingleDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 1-25 2017-12-31 C000654 0-25 2017-12-31 C000654 0-66 2018-01-01 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 4-3 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-12 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-12 2018-01-01 2018-12-31 C000654 0-31 2018-01-01 2018-12-31 C000654 0-16 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 3-1 2018-01-01 2018-12-31 C000654 3-5 2018-01-01 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 0-24 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 1-33 2018-01-01 2018-12-31 C000654 0-2 2018-12-31 C000654 1-18 2018-01-01 2018-12-31 C000654 0-16 0-16 2018-12-31 C000654 0-68 2018-01-01 2018-12-31 C000654 5-18 2018-01-01 2018-12-31 C000654 0-31 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-7 2018-12-31 C000654 1-24 2017-12-31 C000654 5-38 2018-01-01 2018-12-31 C000654 0-74 2018-01-01 2018-12-31 C000654 0-18 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 ferc:MarchMember 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 2-13 2018-01-01 2018-12-31 C000654 1-37 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-6 2017-01-01 2017-12-31 C000654 0-33 2018-01-01 2018-12-31 C000654 0-18 2017-12-31 C000654 0-35 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 8-10 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 2-2 2018-01-01 2018-12-31 C000654 2-21 2018-01-01 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 1-2 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-19 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-6 2018-12-01 2018-12-31 C000654 0-34 2018-01-01 2018-12-31 C000654 8-4 2018-01-01 2018-12-31 C000654 1-10 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 2-13 2018-01-01 2018-12-31 C000654 5-13 2018-01-01 2018-12-31 C000654 0-20 2017-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 2-4 2017-01-01 2017-12-31 C000654 0-28 2018-01-01 2018-12-31 C000654 ferc:DirectPayrollDistributionMember 2018-01-01 2018-12-31 C000654 0-3 0-3 2018-12-31 C000654 1-26 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 0-27 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-33 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 ferc:RecourseRateMember 2018-12-01 2018-12-31 C000654 0-13 2018-12-31 C000654 0-20 2018-01-01 2018-12-31 C000654 2-20 2017-01-01 2017-12-31 C000654 3-5 2018-01-01 2018-12-31 C000654 2-12 2017-01-01 2017-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 1-14 2017-01-01 2017-12-31 C000654 0-23 2018-01-01 2018-12-31 C000654 2-19 2017-01-01 2017-12-31 C000654 0-4 0-4 2017-12-31 C000654 0-28 2018-12-31 C000654 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 1-17 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 2-11 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 0-12 2018-12-31 C000654 3-15 2017-01-01 2017-12-31 C000654 0-27 ferc:GasUtilityMember 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 6-39 2018-01-01 2018-12-31 C000654 6-9 2018-01-01 2018-12-31 C000654 ferc:NonUtilityMember 2018-01-01 2018-12-31 C000654 0-36 2018-01-01 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 2-7 2018-01-01 2018-12-31 C000654 0-34 2018-01-01 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 1-15 2018-01-01 2018-12-31 C000654 0-9 2018-01-01 2018-12-31 C000654 8-7 2018-01-01 2018-12-31 C000654 1-16 2018-01-01 2018-12-31 C000654 2-10 2017-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 1-18 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 5-23 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-2 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 1-30 2018-01-01 2018-12-31 C000654 ferc:GasPlantInServiceMember ferc:GasUtilityMember 2018-12-31 C000654 0-9 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 1-6 2018-01-01 2018-12-31 C000654 0-58 2018-01-01 2018-12-31 C000654 ferc:CreditedMember 2018-11-01 2018-11-30 C000654 0-6 2018-01-01 2018-12-31 C000654 0-33 2018-12-31 C000654 0-6 2018-12-31 C000654 0-9 2018-12-31 C000654 0-72 2018-10-01 2018-10-31 C000654 0-71 2018-10-01 2018-10-31 C000654 1-24 2018-01-01 2018-12-31 C000654 2-12 2018-01-01 2018-12-31 C000654 8-12 2018-01-01 2018-12-31 C000654 0-67 2018-01-01 2018-12-31 C000654 0-3 2018-01-01 2018-12-31 C000654 1-15 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-70 2018-10-01 2018-10-31 C000654 0-19 2018-01-01 2018-12-31 C000654 0-17 2017-12-31 C000654 0-20 2018-01-01 2018-12-31 C000654 1-23 2018-01-01 2018-12-31 C000654 4-23 2018-01-01 2018-12-31 C000654 0-47 2017-01-01 2017-12-31 C000654 7-21 2018-01-01 2018-12-31 C000654 3-7 2018-01-01 2018-12-31 C000654 0-14 0-14 2017-12-31 C000654 2-31 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 0-18 2018-01-01 2018-12-31 C000654 0-31 2018-01-01 2018-12-31 C000654 1-3 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 2-17 2018-01-01 2018-12-31 C000654 4-9 2018-01-01 2018-12-31 C000654 3-10 2018-01-01 2018-12-31 C000654 0-2 2017-12-31 C000654 1-23 2017-01-01 2017-12-31 C000654 0-75 ferc:DirectPayrollDistributionMember 2018-01-01 2018-12-31 C000654 0-31 2018-01-01 2018-12-31 C000654 0-8 2018-01-01 2018-12-31 C000654 0-16 2018-01-01 2018-12-31 C000654 0-11 2018-12-31 C000654 5-25 2018-01-01 2018-12-31 C000654 0-28 2018-01-01 2018-12-31 C000654 0-15 0-15 2018-12-31 C000654 0-14 2018-01-01 2018-12-31 C000654 2-9 2018-01-01 2018-12-31 C000654 8-11 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-67 2018-10-01 2018-10-31 C000654 2-8 2017-01-01 2017-12-31 C000654 5-6 2018-01-01 2018-12-31 C000654 5-35 2018-01-01 2018-12-31 C000654 2-13 2017-01-01 2017-12-31 C000654 0-26 2018-01-01 2018-12-31 C000654 0-10 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 0-16 ferc:GasUtilityMember 2018-12-31 C000654 1-3 2018-01-01 2018-12-31 C000654 0-25 ferc:DeliveredToOthersMember ferc:ThreeDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 ferc:DiscountedRateMember 2018-12-01 2018-12-31 C000654 1-18 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 1-4 2018-01-01 2018-12-31 C000654 0-25 2018-01-01 2018-12-31 C000654 0-36 ferc:DeliveredToOthersMember ferc:ThreeDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 0-14 2018-12-31 C000654 2-7 2018-01-01 2018-12-31 C000654 0-16 2017-12-31 C000654 1-27 2018-01-01 2018-12-31 C000654 0-23 2018-12-31 C000654 1-35 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 0-7 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 2-16 2018-01-01 2018-12-31 C000654 1-15 2018-01-01 2018-12-31 C000654 1-37 2018-01-01 2018-12-31 C000654 0-12 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 6-8 2018-01-01 2018-12-31 C000654 1-20 2018-01-01 2018-12-31 C000654 0-18 2018-12-31 C000654 0-8 2018-12-31 C000654 3-14 2018-01-01 2018-12-31 C000654 8-8 2018-01-01 2018-12-31 C000654 0-14 0-14 2018-01-01 2018-12-31 C000654 2-15 2018-01-01 2018-12-31 C000654 0-15 2018-01-01 2018-12-31 C000654 2-2 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-70 2018-12-01 2018-12-31 C000654 0-14 2018-12-31 C000654 4-8 2018-01-01 2018-12-31 C000654 0-13 2018-01-01 2018-12-31 C000654 2-9 2018-01-01 2018-12-31 C000654 1-17 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-4 2018-01-01 2018-12-31 C000654 1-32 2018-01-01 2018-12-31 C000654 1-20 2018-01-01 2018-12-31 C000654 1-16 2018-01-01 2018-12-31 C000654 1-34 2018-01-01 2018-12-31 C000654 0-4 2017-12-31 C000654 0-29 0 2018-01-01 2018-12-31 C000654 0-16 2017-01-01 2017-12-31 C000654 1-39 2018-01-01 2018-12-31 C000654 0-2 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 0-13 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-24 2018-01-01 2018-12-31 C000654 0-12 2018-01-01 2018-12-31 C000654 1-13 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-65 2018-01-01 2018-12-31 C000654 0-16 ferc:GasPlantInServiceMember ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 3-31 2018-01-01 2018-12-31 C000654 3-6 2018-01-01 2018-12-31 C000654 0-7 2017-12-31 C000654 1-31 2018-12-31 C000654 0-9 2017-01-01 2017-12-31 C000654 0-17 2018-01-01 2018-12-31 C000654 1-23 2018-01-01 2018-12-31 C000654 0-1 0-1 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-11 2018-01-01 2018-12-31 C000654 3-6 2017-01-01 2017-12-31 C000654 1-6 ferc:GasUtilityMember 2018-01-01 2018-12-31 C000654 0-31 ferc:ThreeDayPeakDeliveriesMember 2018-01-01 2018-12-31 C000654 7-28 2018-01-01 2018-12-31 C000654 2-15 2018-01-01 2018-12-31 C000654 0-1 2018-01-01 2018-12-31 C000654 0-5 2018-01-01 2018-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 4-32 2018-01-01 2018-12-31 C000654 1-20 2018-01-01 2018-12-31 C000654 1-25 2018-01-01 2018-12-31 C000654 3-12 2017-01-01 2017-12-31 C000654 0-6 2018-01-01 2018-12-31 C000654 0-15 2018-12-31 iso4217:USD ferc:dth iso4217:USD utr:mi utr:MW utr:KWh pure ferc:dth
THIS FILING IS
Item 1:
An Initial (Original) Submission
OR
Resubmission No.

FERC FINANCIAL REPORT
FERC FORM No. 2: Annual Report of
Major Natural Gas Companies and
Supplemental Form 3-Q: Quarterly
Financial Report

These reports are mandatory under the Natural Gas Act, Sections 10(a), and 16 and 18 CFR Parts 260.1 and 260.300. Failure to report may result in criminal fines, civil penalties, and other sanctions as provided by law. The Federal Energy Regulatory Commission does not consider these reports to be of a confidential nature.
Exact Legal Name of Respondent (Company)

Transcontinental Gas Pipe Line Company, LLC
Year/Period of Report:

End of:
2018
/
Q4


INSTRUCTIONS FOR FILING FERC FORMS 2, 2-A and 3-Q

GENERAL INFORMATION

  1. Purpose

    FERC Forms 2, 2-A, and 3-Q are designed to collect financial and operational information form natural gas companies subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be a non-confidential public use forms.
  2. Who Must Submit

    Each natural gas company whose combined gas transported or stored for a fee exceed 50 million dekatherms in each of the previous three years must submit FERC Form 2 and 3-Q.

    Each natural gas company not meeting the filing threshold for FERC Form 2, but having total gas sales or volume transactions exceeding 200,000 dekatherms in each of the previous three calendar years must submit FERC Form 2-A and 3-Q.

    Newly established entities must use projected data to determine whether they must file the FERC Form 3-Q and FERC Form 2 or 2-A.
  3. What and Where to Submit

    1. Submit Forms 2, 2-A and 3-Q electronically through the submission software at http://www.ferc.gov/docs-filing/eforms/form-2/elec-subm-soft.asp .
    2. The Corporate Officer Certification must be submitted electronically as part of the FERC Form 2 and 3-Q filings.
    3. Submit immediately upon publication, by either eFiling or mailing two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders and any annual financial or statistical report regularly prepared and distributed to bondholders, security analysts, or industry associations. Do not include monthly and quarterly reports. Indicate by checking the appropriate box on Form 2, Page 3, List of Schedules, if the reports to stockholders will be submitted or if no annual report to stockholders is prepared. Unless eFiling the Annual Report to Stockholders, mail these reports to the Secretary of the Commission at:

      Secretary of the Commission
      Federal Energy Regulatory Commission
      888 First Street, NE
      Washington, DC 20426
    4. For the Annual CPA certification, submit with the original submission of this form, a letter or report (not applicable to respondents classified as Class C or Class D prior to January 1, 1984) prepared in conformity with the current standards of reporting which will:
      1. Contain a paragraph attesting to the conformity, in all material respects, of the schedules listed below with the Commission's applicable Uniform Systems of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and
      2. be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 158.10-158.12 for specific qualifications.)

        Reference
        Reference Schedules Pages
        Comparative Balance Sheet 110-113
        Statement of Income 114-117
        Statement of Retained Earnings 118-119
        Statement of Cash Flows 120-121
        Notes to Financial Statements 122-123
      Filers should state in the letter or report, which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist
    5. Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. To further that effort, new selections, “Annual Report to Stockholders” and “CPA Certification Statement,” have been added to the dropdown “pick list” from which companies must choose when eFiling. Further instructions are found on the Commission website at http://www.ferc.gov/help/how-to.asp.
    6. Federal, State and Local Governments and other authorized users may obtain additional blank copies of FERC Form 2 and 2-A free of charge from: http://www.ferc.gov/docs-filing/forms/form-2/form-2.pdf and http://www.ferc.gov/docs-filing/forms/form-2a/form-2a.pdf, respectively. Copies may also be obtained from the Public Reference and Files Maintenance Branch, Federal Energy Regulatory Commission, 888 First Street, NE. Room 2A, Washington, DC 20426 or by calling (202).502-8371
  4. When to Submit:

    FERC Forms 2, 2-A, and 3-Q must be filed by the dates:

    1. FERC Form 2 and 2-A --- by April 18th of the following year (18 C.F.R. §§ 260.1 and 260.2)
    2. FERC Form 3-Q --- Natural gas companies that file a FERC Form 2 must file the FERC Form 3-Q within 60 days after the reporting quarter (18 C.F.R.§ 260.300), and
    3. FERC Form 3-Q --- Natural gas companies that file a FERC Form 2-A must file the FERC Form 3-Q within 70 days after the reporting quarter (18 C.F.R. § 260.300).
  5. Where to Send Comments on Public Reporting Burden.

    The public reporting burden for the Form 2 collection of information is estimated to average 1,623 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for the Form 2A collection of information is estimated to average 250 hours per response. The public reporting burden for the Form 3-Q collection of information is estimated to average 167 hours per response.

    Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512 (a)).

GENERAL INSTRUCTIONS

  1. Prepare all reports in conformity with the Uniform System of Accounts (USofA) (18 C.F.R. Part 201). Interpret all accounting words and phrases in accordance with the USofA.
  2. Enter in whole numbers (dollars or Dth) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year's year to date amounts.
  3. Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely states the fact.
  4. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on the List of Schedules, pages 2 and 3.
  5. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed only for resubmissions.
  6. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
  7. For any resubmissions, submit the electronic filing using the form submission only. Please explain the reason for the resubmission in a footnote to the data field.
  8. Footnote and further explain accounts or pages as necessary.
  9. Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
  10. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different figures were used.
  11. Report all gas volumes in Dth unless the schedule specifically requires the reporting in another unit of measurement.

DEFINITIONS
  1. Btu per cubic foot – The total heating value, expressed in Btu, produced by the combustion, at constant pressure, of the amount of the gas which would occupy a volume of 1 cubic foot at a temperature of 60°F if saturated with water vapor and under a pressure equivalent to that of 30°F, and under standard gravitational force (980.665 cm. per sec) with air of the same temperature and pressure as the gas, when the products of combustion are cooled to the initial temperature of gas and air when the water formed by combustion is condensed to the liquid state (called gross heating value or total heating value).
  2. Commission Authorization -- The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the commission whose authorization was obtained and give date of the authorization.
  3. Dekatherm – A unit of heating value equivalent to 10 therms or 1,000,000 Btu.
  4. Respondent – The person, corporation, licensee, agency, authority, or other legal entity or instrumentality on whose behalf the report is made.

EXCERPTS FROM THE LAW

Natural Gas Act, 15 U.S.C. 717-717w

"Sec. 10(a). Every natural-gas company shall file with the Commission such annual and other periodic or special reports as the Commission may by rules and regulations or order prescribe as necessary or appropriate to assist the Commission in the proper administration of this act. The Commission may prescribe the manner and form in which such reports shall be made and require from such natural-gas companies specific answers to all questions upon which the Commission may need information. The Commission may require that such reports include, among other things, full information as to assets and liabilities, capitalization, investment and reduction thereof, gross receipts, interest dues and paid, depreciation, amortization, and other reserves, cost of facilities, costs of maintenance and operation of facilities for the production, transportation, delivery, use, or sale of natural gas, costs of renewal and replacement of such facilities, transportation, delivery, use and sale of natural gas..."

"Section 16. The Commission shall have power to perform all and any acts, and to prescribe, issue, make, amend, and rescind such orders, rules, and regulations as it may find necessary or appropriate to carry out the provisions of this act. Among other things, such rules and regulations may define accounting, technical, and trade terms used in this act; and may prescribe the form or forms of all statements declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and time within they shall be filed..."

General Penalties

The Commission may assess up to $1 million per day per violation of its rules and regulations. See NGA § 22(a), 15 U.S.C. §717t-1(a).


FERC FORM NO.
2

REPORT OF MAJOR NATURAL GAS COMPANIES
IDENTIFICATION
01 Exact Legal Name of Respondent

Transcontinental Gas Pipe Line Company, LLC
02 Year/ Period of Report


End of:
2018
/
Q4
03 Previous Name and Date of Change (if name changed during year)

/
04 Address of Principal Office at End of Year (Street, City, State, Zip Code)

P.O. Box 1396 Houston, Texas 77251-1396
05 Name of Contact Person

Kathleen Hambleton
06 Title of Contact Person

Controller, Regulated Accounting
07 Address of Contact Person (Street, City, State, Zip Code)

P.O. Box 1396 Houston, Texas 77251-1396
08 Telephone of Contact Person, Including Area Code

713-215-3319
09 This Report is An Original / A Resubmission

(1)
An Original

(2)
A Resubmission
10 Date of Report (Mo, Da, Yr)

04/12/2019
Annual Corporate Officer Certification
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material respects to the Uniform System of Accounts.



11 Name

Ted T. Timmermans
12 Title

Vice President and Chief Acctg Officer
13 Signature

/s/ Ted T. Timmermans
14 Date Signed

04/12/2019
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any false, fictitious or fraudulent statements as to any matter within its jurisdiction.



Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
List of Schedules (Natural Gas Company)
Enter in column (d) the terms "none," "not applicable," or "NA" as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the responses are "none," "not applicable," or "NA."
Line No.
Title of Schedule
(a)
Reference Page No.
(b)
Date Revised
(c)
Remarks
(d)
ScheduleIdentificationAbstract
Identification
1
02-04
ScheduleListOfSchedulesAbstract
List of Schedules (Natural Gas Campnay)
2
REV 12-07
GeneralCorporateInformationAndFinancialStatementsAbstract
GENERAL CORPORATE INFORMATION AND FINANCIAL STATEMENTS
1
ScheduleGeneralInformationAbstract
General Information
101
12-96
2
ScheduleControlOverRespondentAbstract
Control Over Respondent
102
12-96
3
ScheduleCorporationsControlledByRespondentAbstract
Corporations Controlled by Respondent
103
12-96
4
ScheduleSecurityHoldersAndVotingPowersAbstract
Security Holders and Voting Powers
107
12-96
5
ScheduleImportantChangesDuringTheQuarterYearAbstract
Important Changes During the Year
108
12-96
6
ScheduleComparativeBalanceSheetAbstract
Comparative Balance Sheet
REV 06-04
ScheduleComparativeBalanceSheetAssetsAndOtherDebitsAbstract
Comparative Balance Sheet (Assets And Other Debits)
110
REV 06-04
ScheduleComparativeBalanceSheetLiabilitiesOtherCreditsAbstract
Comparative Balance Sheet (Liabilities and Other Credits)
112
REV 06-04
7
ScheduleStatementOfIncomeAbstract
Statement of Income for the Year
114
REV 06-04
8
ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract
Statement of Accumulated Comprehensive Income and Hedging Activities
117
NEW 06-02
9
ScheduleStatementOfRetainedEarningsAbstract
Statement of Retained Earnings for the Year
118
REV 06-04
10
ScheduleStatementOfCashFlowsAbstract
Statement of Cash Flows
120
REV 06-04
11
ScheduleNotesToFinancialStatementsAbstract
Notes to Financial Statements
122.1
REV 12-07
BalanceSheetSupportingSchedulesAssetsAndOtherDebitsAbstract
BALANCE SHEET SUPPORTING SCHEDULES (Assets and Other Debits)
12
ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract
Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization, and Depletion
200
12-96
13
ScheduleGasPlantInServiceAbstract
Gas Plant in Service
204
12-96
14
ScheduleGasPropertyAndCapacityLeasedFromOthersAbstract
Gas Property and Capacity Leased from Others
212
12-96
15
ScheduleGasPropertyAndCapacityLeasedToOthersAbstract
Gas Property and Capacity Leased to Others
213
12-96
N/A
16
ScheduleGasPlantHeldForFutureUseAbstract
Gas Plant Held for Future Use
214
12-96
N/A
17
ScheduleConstructionWorkInProgressGasAbstract
Construction Work in Progress-Gas
216
12-96
18
ScheduleNonTraditionalRateTreatmentAffordedNewProjectsAbstract
Non-Traditional Rate Treatment Afforded New Projects
217
NEW 12-07
19
ScheduleGeneralDescriptionOfConstructionOverheadProcedureAbstract
General Description of Construction Overhead Procedure
218
REV 12-07
20
ScheduleAccumulatedProvisionForDepreciationOfGasUtilityPlantAbstract
Accumulated Provision for Depreciation of Gas Utility Plant
219
12-96
21
ScheduleGasStoredAbstract
Gas Stored
220
REV 04-04
22
ScheduleInvestmentsAbstract
Investments
222
12-96
N/A
23
ScheduleInvestmentsInSubsidiaryCompaniesAbstract
Investments In Subsidiary Companies
224
12-96
24
SchedulePrepaymentsAbstract
Prepayments
230a
12-96
25
ScheduleExtraordinaryPropertyLossesAbstract
Extraordinary Property Losses
230b
12-96
N/A
26
ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract
Unrecovered Plant And Regulatory Study Costs
230c
12-96
N/A
27
ScheduleOtherRegulatoryAssetsAbstract
Other Regulatory Assets
232
REV 12-07
28
ScheduleMiscellaneousDeferredDebitsAbstract
Miscellaneous Deferred Debits
233
12-96
29
ScheduleAccumulatedDeferredIncomeTaxesAbstract
Accumulated Deferred Income Taxes
234
REV 12-07
BalanceSheetSupportingSchedulesLiabilitiesAndOtherCreditsAbstract
BALANCE SHEET SUPPORTING SCHEDULES (Liabilities and Other Credits)
30
ScheduleCapitalStockAbstract
Capital Stock
250
12-96
N/A
31
ScheduleCapitalStockSubscribedLiabilityForConversionPremiumOnAndInstallmentsReceivedOnAbstract
Capital Stock Subscribed, Capital Stock Liability for Conversion, Premium on Capital Stock, and Installments Recieved on Capital Stock
252
12-96
N/A
32
ScheduleOtherPaidInCapitalAbstract
Other Paid-In Capital
253
12-96
33
ScheduleDiscountOnCapitalStockAbstract
Discount on Capital Stock
254
12-96
N/A
34
ScheduleCapitalStockExpenseAbstract
Capital Stock Expense
254
12-96
N/A
35
ScheduleSecuritiesIssuedOrAssumedAndSecuritiesRefundedOrRetiredDuringTheYearAbstract
Securities Issued Or Assumed And Securities Refunded Or Retired During The Year
255.1
12-96
36
ScheduleLongTermDebtAbstract
Long-Term Debt
256
12-96
37
ScheduleUnamortizedDebtExpensePremiumAndDiscountOnLongTermDebtAbstract
Unamortized Debt Expense, Premium And Discount On Long-Term Debt
258
12-96
38
ScheduleUnamortizedLossAndGainOnReacquiredDebtAbstract
Unamortized Loss And Gain On Reacquired Debt
260
12-96
N/A
39
ScheduleReconciliationOfReportedNetIncomeWithTaxableIncomeForFederalIncomeTaxesAbstract
Reconciliation of Reported Net Income with Taxable Income for Federal Income Taxes
261
12-96
40
ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract
Taxes Accrued, Prepaid And Charged During Year, Distribution Of Taxes Charged
262
REV 12-07
41
ScheduleMiscellaneousCurrentAndAccruedLiabilitiesAbstract
Miscellaneous Current And Accrued Liabilities
268
12-96
42
ScheduleOtherDeferredCreditsAbstract
Other Deferred Credits
269
12-96
43
ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract
Accumulated Deferred Income Taxes-Other Property (Account 282)
274
REV 12-07
44
ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract
Accumulated Deferred Income Taxes-Other (Account 283)
276
REV 12-07
45
ScheduleOtherRegulatoryLiabilitiesAbstract
Other Regulatory Liabilities
278
REV 12-07
IncomeAccountSupportingSchedulesAbstract
INCOME ACCOUNT SUPPORTING SCHEDULES
46
ScheduleMonthlyQuantityRevenueDataByRateScheduleAbstract
Monthly Quantity & Revenue Data
299
NEW 12-08
47
ScheduleGasOperatingRevenuesAbstract
Gas Operating Revenues
300
REV 12-07
48
ScheduleRevenuesFromTransporationOfGasOfOthersThroughGatheringFacilitiesAbstract
Revenues From Transportation Of Gas Of Others Through Gathering Facilities
302
12-96
49
ScheduleRevenuesFromTransportationOfGasOfOthersThroughTransmissionFacilitiesAbstract
Revenues From Transportation Of Gas Of Others Through Transmission Facilities
304
12-96
50
ScheduleRevenuesFromStoringGasOfOthersAbstract
Revenues From Storing Gas Of Others
306
12-96
51
ScheduleOtherGasRevenuesAbstract
Other Gas Revenues
308
12-96
52
ScheduleDiscountedRateServicesAndNegotiatedRateServicesAbstract
Discounted Rate Services And Negotiated Rate Services
313
NEW 12-07
53
ScheduleGasOperationAndMaintenanceExpensesAbstract
Gas Operation And Maintenance Expenses
317
12-96
54
ScheduleExchangeAndImbalanceTransactionsAbstract
Exchange And Imbalance Transactions
328
12-96
55
ScheduleGasUsedInUtilityOperationsAbstract
Gas Used In Utility Operations
331
12-96
56
ScheduleTransmissionAndCompressionOfGasByOthersAbstract
Transmission And Compression Of Gas By Others
332
12-96
N/A
57
ScheduleOtherGasSupplyExpensesAbstract
Other Gas Supply Expenses
334
12-96
58
ScheduleMiscellaneousGeneralExpensesAbstract
Miscellaneous General Expenses-Gas
335
12-96
59
ScheduleDepreciationDepletionAndAmortizationOfGasPlantAbstract
Depreciation, Depletion, and Amortization of Gas Plant
12-96
59
ScheduleDepreciationDepletionAndAmortizationAbstract
Section A. Summary of Depreciation, Depletion, and Amortization Charges
336
12-96
59
ScheduleFactorsUsedInEstimatingDepreciationChargesAbstract
Section B. Factors Used in Estimating Depreciation Charges
338
12-96
60
ScheduleParticularsConcerningCertainIncomeDeductionsAndInterestChargesAccountsAbstract
Particulars Concerning Certain Income Deductions And Interest Charges Accounts
340
12-96
CommonSectionAbstract
COMMON SECTION
12-96
61
ScheduleRegulatoryCommissionExpensesAbstract
Regulatory Commission Expenses
350
12-96
62
ScheduleEmployeePensionsAndBenefitsAbstract
Employee Pensions And Benefits (Account 926)
352
NEW 12-07
63
ScheduleDistributionOfSalariesAndWagesAbstract
Distribution Of Salaries And Wages
354
REVISED
64
ScheduleChargesForOutsideProfessionalAndOtherConsultativeServicesAbstract
Charges For Outside Professional And Other Consultative Services
357
REVISED
65
ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract
Transactions With Associated (Affiliated) Companies
358
NEW 12-07
StatisticalDataAbstract
GAS PLANT STATISTICAL DATA
66
ScheduleCompressorStationsAbstract
Compressor Stations
508
REV 12-07
67
ScheduleGasStorageProjectsAbstract
Gas Storage Projects
512
12-96
67
ScheduleGasStorageProjectsByCapacitiesAbstract
Gas Storage Projects
513
12-96
68
ScheduleTransmissionLinesAbstract
Transmission Lines
514
12-96
69
ScheduleTransmissionSystemPeakDeliveriesAbstract
Transmission System Peak Deliveries
518
12-96
70
ScheduleAuxiliaryPeakingFacilitiesAbstract
Auxiliary Peaking Facilities
519
12-96
71
ScheduleGasAccountNaturalGasAbstract
Gas Account - Natural Gas
520
REV 01-11
72
ScheduleShipperSuppliedGasForTheCurrentQuarterAbstract
Shipper Supplied Gas for the Current Quarter
521
REVISED 02-11
73
ScheduleSystemMapsAbstract
System Maps
522.1
REV. 12-96
74
FootnoteReferenceAbstract
Footnote Reference
75
FootnoteTextAbstract
Footnote Text
76
StockholdersReportsAbstract
Stockholder's Reports (check appropriate box)
Four copies will be submitted

No annual report to stockholders is prepared


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
General Information
1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept.

KATHLEEN HAMBLETON CONTROLLER, REGULATED ACCOUNTING P.O. BOX 1396 HOUSTON, TEXAS 77251-1396

2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized.

ON DECEMBER 31, 2008, TRANSCONTINENTAL GAS PIPE LINE CORPORATION, A DELAWARE CORPORATION, WAS CONVERTED TO A DELAWARE LIMITED LIABILITY COMPANY, CHANGING ITS NAME TO TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC.
State of Incorporation:

Date of Incorporation:

Incorporated Under Special Law:

3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased.

NOT APPLICABLE
(a) Name of Receiver or Trustee Holding Property of the Respondent:

(b) Date Receiver took Possession of Respondent Property:

(c) Authority by which the Receivership or Trusteeship was created:

(d) Date when possession by receiver or trustee ceased:

4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC (TRANSCO) WAS ENGAGED DURING 2018 IN THE PURCHASE (1), TRANSMISSION (2), SALE (3), EXCHANGE (4), AND STORAGE (5) OF NATURAL GAS IN INTERSTATE COMMERCE IN THE FOLLOWING STATES: TEXAS (1) (2) (3), LOUISIANA (1) (2) (3) (5), MISSISSIPPI (1) (2) (3) (5), ALABAMA (1) (2) (3) (5), GEORGIA (1) (2) (3) (5), SOUTH CAROLINA (1) (2) (3) (5), NORTH CAROLINA (1) (2) (3) (4) (5), PENNSYLVANIA (1) (2) (3) (4) (5), NEW JERSEY (1) (2) (3) (5), NEW YORK (2) (4) (5), VIRGINIA (1) (2) (3) (5), MARYLAND (1) (2) (3), DELAWARE (2) (5).
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements?

(1)
Yes

(2)
No

Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Control Over Respondent
  1. Report in column (a) the names of all corporations, partnerships, business trusts, and similar organizations that directly, indirectly, or jointly held control (see page 103 for definition of control) over the respondent at the end of the year. If control is in a holding company organization, report in a footnote the chain of organization.
  2. If control is held by trustees, state in a footnote the names of trustees, the names of beneficiaries for whom the trust is maintained, and the purpose of the trust.
  3. In column (b) designate type of control over the respondent. Report an "M" if the company is the main parent or controlling company having ultimate control over the respondent. Otherwise, report a "D" for direct, an "I" for indirect, or a "J" for joint control.
Line No.
NameOfCompanyControllingRespondent
Company Name
(a)
TypeOfControlOverTheRespondent
Type of Control
(b)
StateOfIncorporation
State of Incorporation
(c)
VotingStockOwnedByRespondentPercentage
Percent Voting Stock Owned
(d)
1
(a)
Williams Partners Operating LLC
D
DE


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NameOfCompanyControllingRespondent

 

TRANSCO WAS INDIRECTLY OWNED BY WILLIAMS PARTNERS L.P. (WPZ), A PUBLICLY TRADED DELAWARE LIMITED PARTNERSHIP, WHICH WAS CONSOLIDATED BY THE WILLIAMS COMPANIES, INC. (WILLIAMS). ON AUGUST 10, 2018, WILLIAMS COMPLETED A MERGER WITH WPZ, PURSUANT TO WHICH WILLIAMS ACQUIRED ALL OF THE PUBLICLY HELD OUTSTANDING COMMON UNITS OF WPZ IN EXCHANGE FOR SHARES OF WILLIAMS’ COMMON STOCK (WPZ MERGER). WILLIAMS CONTINUED AS THE SURVIVING ENTITY. TRANSCO IS NOW INDIRECTLY OWNED BY WILLIAMS.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Corporations Controlled by Respondent
  1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
  2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved.
  3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
  4. In column (b) designate type of control of the respondent as "D" for direct, an "I" for indirect, or a "J" for joint control.

---------------------------
DEFINITIONS
---------------------------

  1. See the Uniform System of Accounts for a definition of control.
  2. Direct control is that which is exercised without interposition of an intermediary.
  3. Indirect control is that which is exercised by the interposition of an intermediary that exercises direct control.
  4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line No.
NameOfCompanyControlledByRespondent
Name of Company Controlled
(a)
TypeOfControlOverTheRespondent
Type of Control
(b)
CompanyControlledByRespondentKindOfBusinessDescription
Kind of Business
(c)
VotingStockOwnedByRespondentPercentage
Percent Voting Stock Owned
(d)
FootnoteReferences
Footnote Reference
(e)
1
Cardinal Operating Company, LLC
D
Constructs/Operates
2
Transmission Pipeline
3
Pine Needle Operating Company, LLC
D
Constructs/Operates/LNG
4
Storage Facility
5
(a)
TransCardinal Company, LLC
D
Pipeline Transmission Company
6
(b)
TransCarolina LNG Company, LLC
D
LNG Storage Facility


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NameOfCompanyControlledByRespondent

 

TRANSCARDINAL COMPANY, LLC OWNS APPROXIMATELY 45% OF CARDINAL PIPELINE COMPANY, LLC.

(b) Concept: NameOfCompanyControlledByRespondent

 

TRANSCAROLINA LNG COMPANY, LLC OWNS 35% OF PINE NEEDLE LNG COMPANY, LLC.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
Security Holders and Voting Powers
  1. Give the names and addresses of the 10 security holders of the respondent who, at the date of the latest closing of the stock book or compilation of list of stockholders of the respondent, prior to the end of the year, had the highest voting powers in the respondent, and state the number of votes that each could cast on that date if a meeting were held. If any such holder held in trust, give in a footnote the known particulars of the trust (whether voting trust, etc.), duration of trust, and principal holders of beneficiary interests in the trust. If the company did not close the stock book or did not compile a list of stockholders within one year prior to the end of the year, or if since it compiled the previous list of stockholders, some other class of security has become vested with voting rights, then show such 10 security holders as of the close of the year. Arrange the names of the security holders in the order of voting power, commencing with the highest. Show in column (a) the titles of officers and directors included in such list of 10 security holders.
  2. If any security other than stock carries voting rights, explain in a supplemental statement how such security became vested with voting rights and give other important details concerning the voting rights of such security. State whether voting rights are actual or contingent; if contingent, describe the contingency.
  3. If any class or issue of security has any special privileges in the election of directors, trustees or managers, or in the determination of corporate action by any method, explain briefly in a footnote.
  4. Furnish details concerning any options, warrants, or rights outstanding at the end of the year for others to purchase securities of the respondent or any securities or other assets owned by the respondent, including prices, expiration dates, and other material information relating to exercise of the options, warrants, or rights. Specify the amount of such securities or assets any officer, director, associated company, or any of the 10 largest security holders is entitled to purchase. This instruction is inapplicable to convertible securities or to any securities substantially all of which are outstanding in the hands of the general public where the options, warrants.
1. Give date of the latest closing of the stock book prior to end of year, and, in a footnote, state the purpose of such closing:

2. State the total number of votes cast at the latest general meeting prior to the end of year for election of directors of the respondent and number of such votes cast by proxy.

Total:
By Proxy:
3. Give the date and place of such meeting:

Line No.
Name (Title) and Address of Security Holder
(a)
VOTING SECURITIES
4. Number of votes as of (date):

Total Votes
(b)
Common Stock
(c)
Preferred Stock
(d)
Other
(e)
5
TOTAL votes of all voting securities
6
TOTAL number of security holders
7
TOTAL votes of security holders listed below
8
Williams Partners Operating LLC
9
One Williams Center
10
Tulsa, OK 74172
11
Williams Partners Operating LLC is the sole member of Transcontinental Gas Pipe Line Company, LLC


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Important Changes During the Year
Give details concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Answer each inquiry. Enter "none" or "not applicable" where applicable. If the answer is given elsewhere in the report, refer to the schedule in which it appears.
  1. Changes in and important additions to franchise rights: Describe the actual consideration and state from whom the franchise rights were acquired. If the franchise rights were acquired without the payment of consideration, state that fact.
  2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization.
  3. Purchase or sale of an operating unit or system: Briefly describe the property, and the related transactions, and cite Commission authorization, if any was required. Give date journal entries called for by Uniform System of Accounts were submitted to the Commission.
  4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective dates, lengths of terms, names of parties, rents, and other conditions. State name of Commission authorizing lease and give reference to such authorization.
  5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and cite Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
  6. Obligations incurred or assumed by respondent as guarantor for the performance by another of any agreement or obligation, including ordinary commercial paper maturing on demand or not later than one year after date of issue: State on behalf of whom the obligation was assumed and amount of the obligation. Cite Commission authorization if any was required.
  7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
  8. State the estimated annual effect and nature of any important wage scale changes during the year.
  9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year.
  10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest.
  11. Estimated increase or decrease in annual revenues caused by important rate changes: State effective date and approximate amount of increase or decrease for each revenue classification. State the number of customers affected.
  12. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period.
  13. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.

 

1. N/A

 

2. N/A

 

3. N/A

 

4. N/A

 

5. On March 23, 2018, Transco placed into service the facilities of Phase 2 of the Garden State Expansion Project which created an additional 160,000 dth/day of firm transportation capacity from Transco’s Station 210 Zone 6 Pool to a new delivery point on Transco’s Trenton Woodbury Lateral in Burlington County, New Jersey. In total, the project created 180,000 dth/day of capacity for one customer, New Jersey Natural Gas Company. The service will provide approximately $24.3 million in annual reservation revenue.

On June 1, 2018, Transco placed into service additional mainline facilities for the Atlantic Sunrise Expansion Project which provides 150,000 Mdth/day of additional firm transportation service, on an interim basis until the full project is placed in service, from Transco’s River Road Interconnection in Lancaster County, Virginia to its Station 85 Pooling Point in Choctaw County, Alabama. The interim service will provide revenue of approximately $1.0 million per month, or $12 million annually, and serves three customers.

On October 6, 2018, Transco fully placed into service the Atlantic Sunrise Expansion Project. The full project is 1,700,002 dth/day of firm service from locations on the greenfield Central Penn Line North and existing Leidy Line through the greenfield Central Penn Line South to the River Road Transfer located at mainline milepost 1683.32 for 500,000 Dths, the Pleasant Valley interconnect located at mainline milepost 1586.2 for 350,000 Dths, and Transco’s Zone 4 Station 85 Pool located at mainline milepost 784.66 for 850,002 Dths. The expected reservation revenues (excluding electric power) from the full project is anticipated to be approximately $423million on an annual basis. The project serves nine customers.

On December 21, 2018, Transco began providing 290,000 dth/day of firm transportation service, on an interim basis until the full project is placed in service, for the Gulf Connector Expansion Project from Transco’s Station 65 Pooling Location in St. Helena Parish, Louisiana to Cheniere Corpus Christi Pipeline in San Patricio County, Texas. The interim service will provide revenue of approximately $1.9 million per month, or $23 million annually, and serves one customer.

 

6. N/A

 

7. N/A

 

8. During the first, second, third, and fourth quarters of 2018, the annual effect of our wage scale changes resulted in a base payroll increase of approximately $3.7 million, $0.3 million, $0.3 million, and $0.7 million, respectively.

 

9. N/A

 

10. N/A

 

11. Effective March 23, 2018, Transco placed into service Phase 2 of the Garden State Expansion Project, an incrementally priced transportation project. This project serves one customer who will pay a negotiated reservation rate, not the recourse rate stated in the tariff. The estimated increase in annual revenues for service provided from this expansion project is provided in Item 5 of page 108.1.

Effective October 1, 2018, Transco effectuated certain rate changes included in its August 31, 2018 General Section 4 rate filing in Docket No. RP18-1126 as directed in the Commission’s September 28, 2018 “Order Accepting Tariff Records, Accepting and Suspending Tariff Records, Subject to Refund, and Establishing Hearing and Settlement Judge Procedures.” The effect of the rate changes reflect (1) an estimated decrease of $7.2 million in transportation demand charges for 2018 (an estimated annual decrease of $28.8 million) and (2) an estimated increase of $1.8 million of transportation commodity charges for 2018 (an estimated annual increase of $7.2 million). The rate changes affect approximately 150 customers.

Effective December 21, 2018, Transco began providing interim firm service for the Gulf Connector Expansion Project, an incrementally priced transportation project. The interim service was provided to Corpus Christi Liquefaction, LLC at a negotiated reservation rate, not the recourse rate stated in the tariff. The estimated increase in annual revenues for service provided from this expansion project is provided in Item 5 of page 108.2.

12. Effective April 11, 2018, Ted T. Timmermans resigned as Controller, Kathleen R. Hambleton was elected Controller.

Effective August 24, 2018, Tyler P. Evans resigned as Assistant Secretary.

Effective November 1, 2018, Gary M. Duvall retired as Vice President.

13. N/A



Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Comparative Balance Sheet (Assets And Other Debits)
Line No.
Title of Account
(a)
Reference Page Number
(b)
Current Year End of Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
1
UtilityPlantAbstract
Utility Plant
2
UtilityPlant
Utility Plant (101-106, 114)
200-201
15,752,012,887
12,562,677,365
3
ConstructionWorkInProgress
Construction Work in Progress (107)
200-201
563,912,806
1,240,950,317
4
UtilityPlantAndConstructionWorkInProgress
TOTAL Utility Plant (Total of lines 2 and 3)
200-201
16,315,925,693
13,803,627,682
5
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
(Less) Accum. Provision for Depr., Amort., Depl. (108, 111, 115)
5,644,735,111
5,377,699,428
6
UtilityPlantNet
Net Utility Plant (Total of line 4 less 5)
10,671,190,582
8,425,928,254
7
NuclearFuel
Nuclear Fuel (120.1 thru 120.4, and 120.6)
8
AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies
(Less) Accum. Provision for Amort., of Nuclear Fuel Assemblies (120.5)
9
NuclearFuelNet
Nuclear Fuel (Total of line 7 less 8)
10
UtilityPlantAndNuclearFuelNet
Net Utility Plant (Total of lines 6 and 9)
10,671,190,582
8,425,928,254
11
OtherGasPlantAdjustments
Utility Plant Adjustments (116)
122
12
GasStoredBaseGas
Gas Stored-Base Gas (117.1)
220
76,516,841
76,273,878
13
SystemBalancingGas
System Balancing Gas (117.2)
220
37,427,641
8,867,537
14
GasStoredInReservoirsAndPipelinesNoncurrent
Gas Stored in Reservoirs and Pipelines-Noncurrent (117.3)
220
15
GasOwedToSystemGas
Gas Owed to System Gas (117.4)
220
16
OtherPropertyAndInvestmentsAbstract
OTHER PROPERTY AND INVESTMENTS
17
NonutilityProperty
Nonutility Property (121)
9,872,868
9,872,868
18
AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty
(Less) Accum. Provision for Depreciation and Amortization (122)
844,313
844,313
19
InvestmentInAssociatedCompanies
Investments in Associated Companies (123)
222-223
20
InvestmentInSubsidiaryCompanies
Investments in Subsidiary Companies (123.1)
224-225
10,193,654
12,391,479
22
NoncurrentPortionOfAllowances
Noncurrent Portion of Allowances
23
OtherInvestments
Other Investments (124)
222-223
24
SinkingFunds
Sinking Funds (125)
25
DepreciationFund
Depreciation Fund (126)
26
AmortizationFundFederal
Amortization Fund - Federal (127)
27
OtherSpecialFunds
Other Special Funds (128)
149,629,932
134,738,047
28
DerivativeInstrumentAssetsLongTerm
Long-Term Portion of Derivative Assets (175)
29
DerivativeInstrumentAssetsHedgesLongTerm
Long-Term Portion of Derivative Assets - Hedges (176)
30
OtherPropertyAndInvestments
TOTAL Other Property and Investments (Total of lines 17-20, 22-29)
168,852,141
156,158,081
31
CurrentAndAccruedAssetsAbstract
CURRENT AND ACCRUED ASSETS
32
Cash
Cash (131)
33
SpecialDeposits
Special Deposits (132-134)
214,330
611,174
34
WorkingFunds
Working Funds (135)
35
TemporaryCashInvestments
Temporary Cash Investments (136)
222-223
36
NotesReceivable
Notes Receivable (141)
37
CustomerAccountsReceivable
Customer Accounts Receivable (142)
191,917,372
170,071,766
38
OtherAccountsReceivable
Other Accounts Receivable (143)
9,990,891
2,048,695
39
AccumulatedProvisionForUncollectibleAccountsCredit
(Less) Accum. Provision for Uncollectible Accounts - Credit (144)
7,941
40
NotesReceivableFromAssociatedCompanies
Notes Receivable from Associated Companies (145)
33,034,090
506,354,990
41
AccountsReceivableFromAssociatedCompanies
Accounts Receivable from Associated Companies (146)
2,399,916
3,269,987
42
FuelStock
Fuel Stock (151)
43
FuelStockExpensesUndistributed
Fuel Stock Expenses Undistributed (152)
44
ResidualsAndExtractedProducts
Residuals (Elec) and Extracted Products (Gas) (153)
45
PlantMaterialsAndOperatingSupplies
Plant Materials and Operating Supplies (154)
36,116,923
37,037,044
46
Merchandise
Merchandise (155)
47
OtherMaterialsAndSupplies
Other Materials and Supplies (156)
48
NuclearMaterialsHeldForSale
Nuclear Materials Held for Sale (157)
49
AllowanceInventoryAndWithheld
Allowances (158.1 and 158.2)
50
NoncurrentPortionOfAllowances
(Less) Noncurrent Portion of Allowances
51
StoresExpenseUndistributed
Stores Expense Undistributed (163)
446,064
350,309
52
GasStoredCurrent
Gas Stored Underground-Current (164.1)
220
53
LiquefiedNaturalGasStoredAndHeldForProcessing
Liquefied Natural Gas Stored and Held for Processing (164.2 thru 164.3)
220
875,043
790,239
54
Prepayments
Prepayments (165)
230
8,613,163
8,614,548
55
AdvancesForGas
Advances for Gas (166 thru 167)
56
InterestAndDividendsReceivable
Interest and Dividends Receivable (171)
157,121
119,155
57
RentsReceivable
Rents Receivable (172)
58
AccruedUtilityRevenues
Accrued Utility Revenues (173)
59
MiscellaneousCurrentAndAccruedAssets
Miscellaneous Current and Accrued Assets (174)
4,514,754
3,205,073
60
DerivativeInstrumentAssets
Derivative Instrument Assets (175)
61
DerivativeInstrumentAssetsLongTerm
(Less) Long-Term Portion of Derivative Instrument Assets (175)
62
DerivativeInstrumentAssetsHedges
Derivative Instrument Assets - Hedges (176)
63
DerivativeInstrumentAssetsHedgesLongTerm
(Less) Long-Term Portion of Derivative Instrument Assests - Hedges (176)
64
CurrentAndAccruedAssets
TOTAL Current and Accrued Assets (Total of lines 32 thru 63)
288,271,726
732,472,980
65
DeferredDebitsAbstract
DEFERRED DEBITS
66
UnamortizedDebtExpense
Unamortized Debt Expense (181)
24,241,482
15,377,244
67
ExtraordinaryPropertyLosses
Extraordinary Property Losses (182.1)
230
68
UnrecoveredPlantAndRegulatoryStudyCosts
Unrecovered Plant and Regulatory Study Costs (182.2)
230
69
OtherRegulatoryAssets
Other Regulatory Assets (182.3)
232
582,154,277
445,227,545
70
PreliminarySurveyAndInvestigationCharges
Preliminary Survey and Investigation Charges (Electric)(183)
71
PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges
Preliminary Survey and Investigation Charges (Gas)(183.1 and 183.2)
87,217
72
ClearingAccounts
Clearing Accounts (184)
1,019,151
2,144,430
73
TemporaryFacilities
Temporary Facilities (185)
74
MiscellaneousDeferredDebits
Miscellaneous Deferred Debits (186)
233
9,800,059
3,312,397
75
DeferredLossesFromDispositionOfUtilityPlant
Deferred Losses from Disposition of Utility Plant (187)
76
ResearchDevelopmentAndDemonstrationExpenditures
Research, Development, and Demonstration Expend. (188)
77
UnamortizedLossOnReacquiredDebt
Unamortized Loss on Reacquired Debt (189)
78
AccumulatedDeferredIncomeTaxes
Accumulated Deferred Income Taxes (190)
234-235
(a)
493,044,810
427,562,810
79
UnrecoveredPurchasedGasCosts
Unrecovered Purchased Gas Costs (191)
80
DeferredDebits
TOTAL Deferred Debits (Total of lines 66 thru 79)
1,108,308,694
889,335,566
81
AssetsAndOtherDebits
TOTAL Assets and Other Debits (Total of lines 10-15,30,64,and 80)
12,350,567,625
10,289,036,296


FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxes

 

 

DEF

 

 

 

 

 

TAX

 

 

 

 

 

ACCT

12/31/2018

12/31/2018

 

12/31/2018

 

& CTD

TOTAL

CTD’S

NOT IN

ADJUSTED

 

TYPE

CTD’S

@0.2621

RATE BASE

ADIT

 

 

 

 

 

 

ACCR AUDIT SERVICES A/P

190 NC

$ 282,000

$ 73,923

$ (73,923)

$ -

RESERVE FOR BAD DEBTS

190 NC

7,941

2,082

(2,082)

-

CONTINGENCIES-CURR – DEFAULT

190 NC

1,795,400

470,646

(470,646)

-

REG LIAB-NCURR-RATE BASE RSG 2017

190 NC

803,981,012

210,755,582

 

210,755,582

CONTINGENCIES-SELF INSURANCE LIAB

190 NC

306,197

80,266

(80,266)

-

ENVIRONMENTAL LIABILITY-DEFAULT

190 NC

1,468,000

384,822

(384,822)

-

ENVIRONMENTAL LIABILITY-DEFAULT

190 NC

1,992,000

522,183

(522,183)

-

RESERVE-INVENTORY

190 NC

45,305

11,876

(11,876)

-

OTH LIAB-MISC RESERVE

190 NC

5,214,981

1,367,055

(1,367,055)

-

OTH LIAB-ARO

190 NC

45,713,817

11,983,420

(11,983,420)

-

DEFERRED REV-NCURR TRANS PREPAY

190 NC

9,905,667

2,596,672

(2,596,672)

-

OTHER DEFERRED-ARO

190 NC

326,533,603

85,596,363

(85,596,363)

-

OTH LIAB-RECYCLABLE MATERIAL FUND

190 NC

484

127

(127)

-

OTH LIAB-NC-ADDITIONAL MIN LIAB

190 NC

1,290,182

338,208

(338,208)

-

INT EXP -263A – PP&E COST ADJ

190 NC

311,996,115

81,786,662

-

81,786,662

PP&E COST ADJ-CIACS

190 NC

370,317,093

97,074,923

(97,074,923)

-     

 

 

$ 1,880,849,797

$ 493,044,810

$ (200,502,566)

$ 292,542,244


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Comparative Balance Sheet (Liabilities and Other Credits)
Line No.
Title of Account
(a)
Reference Page Number
(b)
Current Year End of Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
1
ProprietaryCapitalAbstract
PROPRIETARY CAPITAL
2
CommonStockIssued
Common Stock Issued (201)
250-251
3
PreferredStockIssued
Preferred Stock Issued (204)
250-251
4
CapitalStockSubscribed
Capital Stock Subscribed (202, 205)
252
5
StockLiabilityForConversion
Stock Liability for Conversion (203, 206)
252
6
PremiumOnCapitalStock
Premium on Capital Stock (207)
252
7
OtherPaidInCapital
Other Paid-In Capital (208-211)
253
3,117,858,116
2,777,858,116
8
InstallmentsReceivedOnCapitalStock
Installments Received on Capital Stock (212)
252
9
DiscountOnCapitalStock
(Less) Discount on Capital Stock (213)
254
10
CapitalStockExpense
(Less) Capital Stock Expense (214)
254
11
RetainedEarnings
Retained Earnings (215, 215.1, 216)
118-119
1,761,598,593
1,662,455,417
12
UnappropriatedUndistributedSubsidiaryEarnings
Unappropriated Undistributed Subsidiary Earnings (216.1)
118-119
497,829
163,556
13
ReacquiredCapitalStock
(Less) Reacquired Capital Stock (217)
250-251
14
AccumulatedOtherComprehensiveIncome
Accumulated Other Comprehensive Income (219)
117
391,790
251,000
15
ProprietaryCapital
TOTAL Proprietary Capital (Total of lines 2 thru 14)
4,880,346,328
4,440,400,977
16
LongTermDebtAbstract
LONG TERM DEBT
17
Bonds
Bonds (221)
256-257
207,500,000
207,500,000
18
ReacquiredBonds
(Less) Reacquired Bonds (222)
256-257
19
AdvancesFromAssociatedCompanies
Advances from Associated Companies (223)
256-257
20
OtherLongTermDebt
Other Long-Term Debt (224)
256-257
2,775,000,000
2,025,000,000
21
UnamortizedPremiumOnLongTermDebt
Unamortized Premium on Long-Term Debt (225)
258-259
22
UnamortizedDiscountOnLongTermDebtDebit
(Less) Unamortized Discount on Long-Term Debt-Dr (226)
258-259
11,137,082
5,042,665
23
CurrentPortionOfLongTermDebt
(Less) Current Portion of Long-Term Debt
24
LongTermDebt
TOTAL Long-Term Debt (Total of lines 17 thru 23)
2,971,362,918
2,227,457,335
25
OtherNoncurrentLiabilitiesAbstract
OTHER NONCURRENT LIABILITIES
26
ObligationsUnderCapitalLeaseNoncurrent
Obligations Under Capital Leases-Noncurrent (227)
1,051,866,803
229,359,773
27
AccumulatedProvisionForPropertyInsurance
Accumulated Provision for Property Insurance (228.1)
28
AccumulatedProvisionForInjuriesAndDamages
Accumulated Provision for Injuries and Damages (228.2)
29
AccumulatedProvisionForPensionsAndBenefits
Accumulated Provision for Pensions and Benefits (228.3)
30
AccumulatedMiscellaneousOperatingProvisions
Accumulated Miscellaneous Operating Provisions (228.4)
31
AccumulatedProvisionForRateRefunds
Accumulated Provision for Rate Refunds (229)
32
LongTermPortionOfDerivativeInstrumentLiabilities
Long-Term Portion of Derivative Instrument Liabilities
33
LongTermPortionOfDerivativeInstrumentLiabilitiesHedges
Long-Term Portion of Derivative Instrument Liabilities - Hedges
34
AssetRetirementObligations
Asset Retirement Obligations (230)
394,322,561
363,956,090
35
OtherNoncurrentLiabilities
TOTAL Other Noncurrent Liabilities (Total of lines 26 thru 34)
1,446,189,364
593,315,863
36
CurrentAndAccruedLiabilitiesAbstract
CURRENT AND ACCRUED LIABILITIES
37
CurrentPortionOfLongTermDebt
Current Portion of Long-Term Debt
38
NotesPayable
Notes Payable (231)
39
AccountsPayable
Accounts Payable (232)
218,028,479
469,156,393
40
NotesPayableToAssociatedCompanies
Notes Payable to Associated Companies (233)
41
AccountsPayableToAssociatedCompanies
Accounts Payable to Associated Companies (234)
53,273,405
47,150,115
42
CustomerDeposits
Customer Deposits (235)
36,399,754
15,754,164
43
TaxesAccrued
Taxes Accrued (236)
262-263
23,308,028
12,713,409
44
InterestAccrued
Interest Accrued (237)
70,955,177
49,900,406
45
DividendsDeclared
Dividends Declared (238)
46
MaturedLongTermDebt
Matured Long-Term Debt (239)
47
MaturedInterest
Matured Interest (240)
48
TaxCollectionsPayable
Tax Collections Payable (241)
49
MiscellaneousCurrentAndAccruedLiabilities
Miscellaneous Current and Accrued Liabilities (242)
268
14,050,896
10,971,581
50
ObligationsUnderCapitalLeasesCurrent
Obligations Under Capital Leases-Current (243)
15,419,141
1,565,538
51
DerivativesInstrumentLiabilities
Derivative Instrument Liabilities (244)
52
LongTermPortionOfDerivativeInstrumentLiabilities
(Less) Long-Term Portion of Derivative Instrument Liabilities
53
DerivativeInstrumentLiabilitiesHedges
Derivative Instrument Liabilities - Hedges (245)
54
LongTermPortionOfDerivativeInstrumentLiabilitiesHedges
(Less) Long-Term Portion of Derivative Instrument Liabilities - Hedges
55
CurrentAndAccruedLiabilities
TOTAL Current and Accrued Liabilities (Total of lines 37 thru 54)
431,434,880
607,211,606
56
DeferredCreditsAbstract
DEFERRED CREDITS
57
CustomerAdvancesForConstruction
Customer Advances for Construction (252)
36,652,499
80,271,022
58
AccumulatedDeferredInvestmentTaxCredits
Accumulated Deferred Investment Tax Credits (255)
77,195
100,679
59
DeferredGainsFromDispositionOfUtilityPlant
Deferred Gains from Disposition of Utility Plant (256)
60
OtherDeferredCredits
Other Deferred Credits (253)
269
17,828,548
16,647,017
61
OtherRegulatoryLiabilities
Other Regulatory Liabilities (254)
278
941,269,726
966,684,630
62
UnamortizedGainOnReacquiredDebt
Unamortized Gain on Reacquired Debt (257)
260
63
AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty
Accumulated Deferred Income Taxes - Accelerated Amortization (281)
64
AccumulatedDeferredIncomeTaxesOtherProperty
Accumulated Deferred Income Taxes - Other Property (282)
(a)
1,499,831,664
1,276,602,664
65
AccumulatedDeferredIncomeTaxesOther
Accumulated Deferred Income Taxes - Other (283)
(b)
125,574,503
80,344,503
66
DeferredCredits
TOTAL Deferred Credits (Total of lines 57 thru 65)
2,621,234,135
2,420,650,515
67
LiabilitiesAndOtherCredits
TOTAL Liabilities and Other Credits (Total of lines 15,24,35,55,and 66)
12,350,567,625
10,289,036,296


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOtherProperty

 

 

 

 

 

 

 

 

 

 

DEF

 

 

 

 

 

 

 

 

TAX

 

 

 

 

 

 

 

 

ACCT

12/31/2018

 

12/31/2018

 

 

 

12/31/2018

 

& CTD

TOTAL

 

CTD’S

 

NOT IN

 

ADJUSTED

 

TYPE

CTD’S

 

@0.2621

 

RATE BASE

 

ADIT

 

 

 

 

 

 

 

 

 

PP&E COST ADJ – SOFTWARE DEVELOP

282 NC

(250,825,196)

 

(65,751,317)

 

-

 

(65,751,317)

PP&E COST ADJ – SMART PIGGING

282 NC

(91,944,745)

 

(24,102,395)

 

-

 

(24,102,395)

INT EXP-AFUDC EQUITY-PP&E COST ADJ

282 NC

(486,472,646)

 

(127,523,939)

 

-

 

(127,523,939)

PP&E COST ADJ – ARO

282 NC

(116,040,011)

 

(30,422,930)

 

30,422,930

 

-

PP&E COST ADJ – OTHER

282 NC

(9,763,775)

 

(2,559,476)

 

-

 

(2,559,476)

PP&E COST ADJ – TAX REPAIR

282 NC

(1,354,873,812)

 

(355,166,621)

 

-

 

(355,166,621)

BOOK DEPRECIATION

282 NC

6,698,800,663

 

1,756,023,606

 

(6,277,589)

 

1,749,746,017

TAX DEPRECIATION

282 NC

(9,846,413,246)

 

(2,581,138,768)

 

60,757,583

 

(2,520,381,185)

TAX DEPRECIATION - STEPUP

283 NC

(184,371,506)

 

(48,331,147)

 

48,331,147

 

-

PP&E DEPRECIATION ADJ – ARO

282 NC

26,622,739

 

6,978,885

 

(6,978,885)

 

-

ARO COST OF REMOVAL 481(a) ADJ

282 NC

(56,621,037)

 

(14,842,639)

 

14,842,639

 

-

BOOK GAIN/LOSS – SALE PP&E

282 NC

(12,763,026)

 

(3,345,700)

 

-

 

(3,345,700)

TAX GAIN/LOSS – SALE PP&E

282 NC

(54,595,540)

 

(14,311,675)

 

-

 

(14,311,675)

TAX GAIN/LOSS SEC 481A ADD BACK

282 NC

17,786,116

 

4,662,452

 

-

 

4,662,452

 

 

(5,721,475,022)

 

(1,499,831,664)

 

141,097,825

 

(1,358,733,839)

(b) Concept: AccumulatedDeferredIncomeTaxesOther

 

 

DEF

 

 

 

 

 

TAX

 

 

 

 

 

ACCT

12/31/2018

12/31/2018

 

12/31/2018

 

& CTD

TOTAL

CTD’S

NOT IN

ADJUSTED

 

TYPE

CTD’S

@0.3825

RATE BASE

ADIT

 

 

 

 

 

 

BOOK GAIN/LOSS - ARO TRUST FUND

283 NC

$ (5,064,547)

$ (1,327,620)

$ 1,327,620

$ -

TAX GAIN/LOSS - ARO TRUST FUND 109

283 NC

5,075,358

1,330,454

(1,330,454)

-

PREPAID INSURANCE – DEFAULT

283 NC

(592,396)

(155,291)

155,291

-

PREPAID INSURANCE – PROPERTY

283 NC

(3,934,505)

(1,031,391)

1,031,391

-

PREPAID INSURANCE – EXCESS LIAB

283 NC

(2,946,313)

(772,346)

772,346

-

PREPAID FERC ACA FEES – OTH ASSETS

283 NC

(3,741,356)

(980,759)

980,759

-

OTH ASSETS - CURR-SPECIAL DEPOSITS

283 NC

(57,330)

(15,028)

15,028

-

OTHER DEF CHRGS-ARO TSTFD UNREAL G/L

283 NC

(9,451,485)

(2,477,612)

2,477,612

-

OTH ASSET-NCURR-PROJ FEASIBILITY COST

283 NC

490,362

128,543

(128,543)

-

REG ASSET-CURR-DEF TAX – RATE BASE

283 NC

(1,077,783)

(282,530)

-

(282,530)

REG ASSET-CURR-FTRKR LNG

283 NC

(1,120,307)

(293,677)

293,677

-

REG ASSET-CURR-FTRKR CC LNG

283 NC

(143,648)

(37,656)

37,656

-

REG ASSET-CURR-FTRKR-TRAN DEF

283 NC

(48,353,230)

(12,675,316)

12,675,316

-

REG ASSET-CURR-FTRKR TRAN-CC STOR

283 NC

(1,055,190)

(276,608)

276,608

-

REG ASSET-CURR-ARO-EMINENCE

283 NC

(4,856,500)

(1,273,083)

1,273,083

-

REG ASSET-CURR-FTRKR STORAGE DEF

283 NC

(10,127,986)

(2,654,950)

2,654,950

-

REG ASSET-CURR-FTRKR-CC TRAN

283 NC

(2,120,299)

(555,815)

555,815

-

REG ASSET-CURR-ASSET RET OBL

283 NC

(28,615,028)

(7,501,143)

7,501,143

-

REG LIAB-CURR-OFO RESERVE PENALTY

283 NC

2,390,450

626,633

(626,633)

-

REG LIAB –CURR-ELEC PWR DEF DEMND

283 NC

(1,315,103)

(344,741)

344,741

-

REG LIAB-NC-SENTINEL EXPENSE

283 NC

102,369

26,835

(26,835)

-

REG LIAB-CURR-RETIREE MED LIFE FAS 106

283 NC

2,542,305

666,440

(666,440)

-

REG LIAB-CURR-TRANS OVERRUN

283 NC

1,720

451

(451)

-

REG LIAB-CURR-ELEC PWR CARRYING CHG

283 NC

1,367,145

358,383

(358,383)

-

REG LIAB-CURR-DEFAULT-UNAUTH TAKE DEF

283 NC

8,615

2,258

(2,258)

-

REG ASSET NC-DEF TAX-RATE BASE

283 NC

(1,602,343)

(420,038)

-

(420,038)

REG ASSET-NC-ARO-EMINENCE

283 NC

(40,632,422)

(10,651,383)

10,651,383

-

REG ASSET NC-ARO TRUST WITHD DEF

283 NC

(1,252,730)

(328,391)

328,391

-

REG ASSET NC-CASHOUT DEFERRAL

283 NC

(54,865,680)

(14,382,489)

14,382,489

-

INT EXP-REG ASSET-AFUDC EQUITY

283 NC

(156,784,917)

(41,099,598)

-

(41,099,598)

REG ASSET-NC-ARO

283 NC

(142,024,629)

(37,230,624)

37,230,624

-

REG LIAB-NC-DEFAULT FAS 106

283 NC

54,359,330

14,249,755

(14,249,755)

-

REG LIAB NC-DEF GAS COST

283 NC

(4,031,755)

(1,056,884)

1,056,884

-

REG ASSET – DEFERRED TAX RATE BASE 2018

283 NC

(85,189,830)

(22,331,662)

-

(22,331,662)

REG LIAB-NC-SENTINEL EXPENSE

283 NC

6,341,876

1,662,459

(1,662,459)

-

REG LIAB-NC-PBOP DEF COLL

283 NC

22,942,198

6,014,068

(6,014,068)

-

REG LIAB-NC-PENSION DEF COLL

283 NC

48,548,036

12,726,382

(12,726,382)

-

PP&E COST ADJ-MISC (734B)

283 NC

8,543,576

2,239,613

(2,239,613)

-

TAX DEPRECIATION (734B)

283 NC

(21,027,881)

(5,512,249)

5,512,249

-

TAX GAIN/LOSS-SALE PP&E (734B)

283 NC

236,922

62,107

(62,107)

-

 

 

$ (479,034,931)

$ (125,574,503)

$ 61,440,674

$(64,133,829)


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Statement of Income
Quarterly
  1. Enter in column (d) the balance for the reporting quarter and in column (e) the balance for the same three month period for the prior year.
  2. Report in column (f) the quarter to date amounts for electric utility function; in column (h) the quarter to date amounts for gas utility, and in (j) the quarter to date amounts for other utility function for the current year quarter.
  3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in (k) the quarter to date amounts for other utility function for the prior year quarter.
  4. If additional columns are needed place them in a footnote.

Annual or Quarterly, if applicable
  1. Do not report fourth quarter data in columns (e) and (f)
  2. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
  3. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
  4. Report data for lines 8, 10 and 11 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 407.1 and 407.2.
  5. Use page 122 for important notes regarding the statement of income for any account thereof.
  6. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
  7. Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income, and expense accounts.
  8. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
  9. Enter on page 122 a concise explanation of only those changes in accounting mehods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
  10. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
  11. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.
Title of Account
(a)
Reference Page Number
(b)
Total Current Year to Date Balance for Quarter/Year
(c)
Total Prior Year to Date Balance for Quarter/Year
(d)
Current Three Months Ended Quarterly Only No Fourth Quarter
(e)
Prior Three Months Ended Quarterly Only No Fourth Quarter
(f)
Elec. Utility Current Year to Date (in dollars)
(g)
Elec. Utility Previous Year to Date (in dollars)
(h)
Gas Utiity Current Year to Date (in dollars)
(i)
Gas Utility Previous Year to Date (in dollars)
(j)
Other Utility Current Year to Date (in dollars)
(k)
Other Utility Previous Year to Date (in dollars)
(l)
1
UtilityOperatingIncomeAbstract
UTILITY OPERATING INCOME
2
OperatingRevenues
Gas Operating Revenues (400)
300-301
2,025,955,030
1,789,231,275
2,025,955,030
1,789,231,275
3
OperatingExpensesAbstract
Operating Expenses
4
OperationExpense
Operation Expenses (401)
317-325
697,016,150
670,961,737
697,016,150
670,961,737
5
MaintenanceExpense
Maintenance Expenses (402)
317-325
63,690,054
34,241,734
63,690,054
34,241,734
6
DepreciationExpense
Depreciation Expense (403)
336-338
328,977,598
284,894,436
328,977,598
284,894,436
7
DepreciationExpenseForAssetRetirementCosts
Depreciation Expense for Asset Retirement Costs (403.1)
336-338
7,744,824
7,746,387
7,744,824
7,746,387
8
AmortizationAndDepletionOfUtilityPlant
Amort. & Depl. of Utility Plant (404-405)
336-338
5,105,044
4,867,680
5,105,044
4,867,680
9
AmortizationOfGasPlantAcquisitionAdjustments
Amortization of Utility Plant Acu. Adjustment (406)
336-338
10
AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts
Amort. of Prop. Losses, Unrecovered Plant and Reg. Study Costs (407.1)
11
AmortizationOfConversionExpenses
Amortization of Conversion Expenses (407.2)
12
RegulatoryDebits
Regulatory Debits (407.3)
82,728,618
86,433,652
82,728,618
86,433,652
13
RegulatoryCredits
(Less) Regulatory Credits (407.4)
95,432,618
104,014,586
95,432,618
104,014,586
14
TaxesOtherThanIncomeTaxesUtilityOperatingIncome
Taxes Other Than Income Taxes (408.1)
262-263
76,237,688
73,431,358
76,237,688
73,431,358
15
IncomeTaxesUtilityOperatingIncome
Income Taxes-Federal (409.1)
262-263
97,505,000
32,449,000
97,505,000
32,449,000
16
IncomeTaxesUtilityOperatingIncomeOther
Income Taxes-Other (409.1)
262-263
26,873,000
4,549,000
26,873,000
4,549,000
17
ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome
Provision of Deferred Income Taxes (410.1)
234-235
382,013,168
1,566,548,546
382,013,168
1,566,548,546
18
ProvisionForDeferredIncomeTaxesCreditUtilityOperatingIncome
(Less) Provision for Deferred Income Taxes-Credit (411.1)
234-235
345,170,235
1,305,946,000
345,170,235
1,305,946,000
19
InvestmentTaxCreditAdjustments
Investment Tax Credit Adjustment-Net (411.4)
20
GainsFromDispositionOfPlant
(Less) Gains from Disposition of Utility Plant (411.6)
2,936,808
2,412,936
2,936,808
2,412,936
21
LossesFromDispositionOfUtilityPlant
Losses from Disposition of Utility Plant (411.7)
3,687,469
858,841
3,687,469
858,841
22
GainsFromDispositionOfAllowances
(Less) Gains from Disposition of Allowances (411.8)
23
LossesFromDispositionOfAllowances
Losses from Disposition of Allowances (411.9)
24
AccretionExpense
Accretion Expense (411.10)
32,923,431
104,659,308
32,923,431
104,659,308
25
UtilityOperatingExpenses
TOTAL Utility Operating Expenses (Total of lines 4 thru 24)
1,345,472,735
1,369,779,383
1,345,472,735
1,369,779,383
26
NetUtilityOperatingIncome
Net Utility Operating Income (Total of lines 2 less 25) (Carry forward to line 27)
680,482,295
419,451,892
680,482,295
419,451,892
28
OtherIncomeAndDeductionsAbstract
OTHER INCOME AND DEDUCTIONS
29
OtherIncomeAbstract
Other Income
30
NonutilityOperatingIncomeAbstract
Nonutilty Operating Income
31
RevenuesFromMerchandisingJobbingAndContractWork
Revenues From Merchandising, Jobbing and Contract Work (415)
32
CostsAndExpensesOfMerchandisingJobbingAndContractWork
(Less) Costs and Expense of Merchandising, Job & Contract Work (416)
33
RevenuesFromNonutilityOperations
Revenues From Nonutility Operations (417)
34
ExpensesOfNonutilityOperations
(Less) Expenses of Nonutility Operations (417.1)
35
NonoperatingRentalIncome
Nonoperating Rental Income (418)
36
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings of Subsidiary Companies (418.1)
119
661,385
3,835,303
37
InterestAndDividendIncome
Interest and Dividend Income (419)
11,054,842
6,288,177
38
AllowanceForOtherFundsUsedDuringConstruction
Allowance for Other Funds Used During Construction (419.1)
87,110,999
69,653,114
39
MiscellaneousNonoperatingIncome
Miscellaneous Nonoperating Income (421)
2,947,869
19,293,114
40
GainOnDispositionOfProperty
Gain on Disposition of Property (421.1)
41
OtherIncome
TOTAL Other Income (Total of lines 31 thru 40)
95,879,357
91,399,102
42
OtherIncomeDeductionsAbstract
Other Income Deductions
43
LossOnDispositionOfProperty
Loss on Disposition of Property (421.2)
278,021
44
MiscellaneousAmortization
Miscellaneous Amortization (425)
45
Donations
Donations (426.1)
340
245,300
450,053
46
LifeInsurance
Life Insurance (426.2)
47
Penalties
Penalties (426.3)
862,400
449,051
48
ExpendituresForCertainCivicPoliticalAndRelatedActivities
Expenditures for Certain Civic, Political and Related Activities (426.4)
493,860
513,370
49
OtherDeductions
Other Deductions (426.5)
1,871,929
25,911
50
OtherIncomeDeductions
TOTAL Other Income Deductions (Total of lines 43 thru 49)
340
3,473,489
1,716,406
51
TaxesApplicableToOtherIncomeAndDeductionsAbstract
Taxes Applic. to Other Income and Deductions
52
TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions
Taxes Other Than Income Taxes (408.2)
262-263
53
IncomeTaxesFederal
Income Taxes-Federal (409.2)
262-263
682,000
2,152,000
54
IncomeTaxesOther
Income Taxes-Other (409.2)
262-263
55
ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions
Provision for Deferred Income Taxes (410.2)
234-235
56
ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions
(Less) Provision for Deferred Income Taxes-Credit (411.2)
234-235
57
InvestmentTaxCreditAdjustmentsNonutilityOperations
Investment Tax Credit Adjustments-Net (411.5)
58
InvestmentTaxCredits
(Less) Investment Tax Credits (420)
23,484
23,484
59
TaxesOnOtherIncomeAndDeductions
TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)
658,516
2,128,516
60
NetOtherIncomeAndDeductions
Net Other Income and Deductions (Total of lines 41, 50, 59)
91,747,352
87,554,180
61
InterestChargesAbstract
INTEREST CHARGES
62
InterestOnLongTermDebt
Interest on Long-Term Debt (427)
173,109,056
146,706,000
63
AmortizationOfDebtDiscountAndExpense
Amortization of Debt Disc. and Expense (428)
258-259
1,749,182
1,338,868
64
AmortizationOfLossOnReacquiredDebt
Amortization of Loss on Reacquired Debt (428.1)
40,595
65
AmortizationOfPremiumOnDebtCredit
(Less) Amortization of Premium on Debt-Credit (429)
258-259
66
AmortizationOfGainOnReacquiredDebtCredit
(Less) Amortization of Gain on Reacquired Debt-Credit (429.1)
67
InterestOnDebtToAssociatedCompanies
Interest on Debt to Associated Companies (430)
340
60,062
60,424
68
OtherInterestExpense
Other Interest Expense (431)
340
43,522,862
10,573,388
69
AllowanceForBorrowedFundsUsedDuringConstructionCredit
(Less) Allowance for Borrowed Funds Used During Construction-Credit (432)
29,236,076
22,360,135
70
NetInterestCharges
Net Interest Charges (Total of lines 62 thru 69)
189,205,086
136,359,140
71
IncomeBeforeExtraordinaryItems
Income Before Extraordinary Items (Total of lines 27, 60 and 70)
583,024,561
370,646,932
72
ExtraordinaryItemsAbstract
EXTRAORDINARY ITEMS
73
ExtraordinaryIncome
Extraordinary Income (434)
74
ExtraordinaryDeductions
(Less) Extraordinary Deductions (435)
75
NetExtraordinaryItems
Net Extraordinary Items (Total of line 73 less line 74)
76
IncomeTaxesExtraordinaryItems
Income Taxes-Federal and Other (409.3)
262-263
77
ExtraordinaryItemsAfterTaxes
Extraordinary Items after Taxes (line 75 less line 76)
78
NetIncomeLoss
Net Income (Total of line 71 and 77)
583,024,561
370,646,932


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Statement of Accumulated Comprehensive Income and Hedging Activities
  1. Report in columns (b) (c) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
  2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
  3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
Line No.
Item
(a)
Unrealized Gains and Losses on available-for-sale securities
(b)
Minimum Pension liabililty Adjustment (net amount)
(c)
Foreign Currency Hedges
(d)
Other Adjustments
(e)
Other Cash Flow Hedges Interest Rate Swaps
(f)
Other Cash Flow Hedges [Insert Footnote at Line 1 to specify]
(g)
Totals for each category of items recorded in Account 219
(h)
Net Income (Carried Forward from Page 114, Line 78)
(i)
Total Comprehensive Income
(j)
1
Balance of Account 219 at Beginning of Preceding Year
5,421
5,421
2
Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income
77,098
77,098
3
Preceding Quarter/Year to Date Changes in Fair Value
168,481
168,481
4
Total (lines 2 and 3)
245,579
245,579
370,646,932
370,892,511
5
Balance of Account 219 at End of Preceding Quarter/Year
(a)
251,000
251,000
6
Balance of Account 219 at Beginning of Current Year
(b)
251,000
251,000
7
Current Quarter/Year to Date Reclassifications from Account 219 to Net Income
109,749
109,749
8
Current Quarter/Year to Date Changes in Fair Value
250,539
250,539
9
Total (lines 7 and 8)
140,790
140,790
583,024,561
583,165,351
10
Balance of Account 219 at End of Current Quarter/Year
(c)
391,790
391,790


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: AccumulatedOtherComprehensiveIncomeLossOtherCashFlowHedgesInterestRateSwapsBalance

 

EQUITY INTEREST IN UNDERLYING OTHER COMPREHENSIVE INCOME OF SUBSIDIARIES.

(b) Concept: AccumulatedOtherComprehensiveIncomeLossOtherCashFlowHedgesInterestRateSwapsBalance

 

EQUITY INTEREST IN UNDERLYING OTHER COMPREHENSIVE INCOME OF SUBSIDIARIES.

(c) Concept: AccumulatedOtherComprehensiveIncomeLossOtherCashFlowHedgesInterestRateSwapsBalance

 

EQUITY INTEREST IN UNDERLYING OTHER COMPREHENSIVE INCOME OF SUBSIDIARIES.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
Statement of Retained Earnings
  1. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year.
  2. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b).
  3. State the purpose and amount for each reservation or appropriation of retained earnings.
  4. List first Account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items, in that order.
  5. Show dividends for each class and series of capital stock.
Line No.
Item
(a)
Contra Primary Account Affected
(b)
Current Quarter/Year Year to Date Balance
(c)
Previous Quarter/Year Year to Date Balance
(d)
UnappropriatedRetainedEarningsAbstract
UNAPPROPRIATED RETAINED EARNINGS
1
UnappropriatedRetainedEarnings
Balance-Beginning of Period
1,662,455,417
1,715,884,381
2
ChangesAbstract
Changes (Identify by prescribed retained earnings accounts)
3
AdjustmentsToRetainedEarningsAbstract
Adjustments to Retained Earnings (Account 439)
3.1
AdjustmentsToRetainedEarningsCredit
TOTAL Credits to Retained Earnings (Account 439) (footnote details)
3.2
AdjustmentsToRetainedEarningsCredit
TOTAL Debits to Retained Earnings (Account 439) (footnote details)
3.3
AdjustmentsToRetainedEarningsCredit
Balance Transferred from Income (Acct 433 less Acct 418.1)
582,363,176
374,482,235
4
AdjustmentsToRetainedEarningsCredit
Adjustments to Retained Earnings Credit (Debit)
7
AppropriationsOfRetainedEarningsAbstract
Appropriations of Retained Earnings (Account 436)
7.1
AppropriationsOfRetainedEarnings
TOTAL Appropriations of Retained Earnings (Account 436) (footnote details)
8
AppropriationsOfRetainedEarnings
Appropriations of Retained Earnings Amount
9
DividendsDeclaredPreferredStockAbstract
Dividends Declared-Preferred Stock (Account 437)
9.1
DividendsDeclaredPreferredStock
TOTAL Dividends Declared-Preferred Stock (Account 437) (footnote details)
10
DividendsDeclaredPreferredStock
Dividends Declared-Preferred Stock Amount
11
DividendsDeclaredCommonStockAbstract
Dividends Declared-Common Stock (Account 438)
11.1
DividendsDeclaredCommonStock
TOTAL Dividends Declared-Common Stock (Account 438) (footnote details)
(a)
483,220,000
(b)
427,911,199
12
DividendsDeclaredCommonStock
Dividends Declared-Common Stock Amount
13
TransfersFromUnappropriatedUndistributedSubsidiaryEarnings
Transfers from Account 216.1, Unappropriated Undistributed Subsidiary Earnings
14
UnappropriatedRetainedEarnings
Balance-End of Period (Total of lines 1, 4, 5, 6, 8, 10, 12, and 13)
1,761,598,593
1,662,455,417
15
AppropriatedRetainedEarningsAbstract
APPROPRIATED RETAINED EARNINGS (Account 215)
16
AppropriatedRetainedEarnings
TOTAL Appropriated Retained Earnings (Account 215) (footnote details)
17
AppropriatedRetainedEarningsAmortizationReserveFederalAbstract
APPROPRIATED RETAINED EARNINGS-AMORTIZATION RESERVE, FEDERAL (Account 215.1)
18
AppropriatedRetainedEarningsAmortizationReserveFederal
TOTAL Appropriated Retained Earnings-Amortization Reserve, Federal (Account 215.1)
19
AppropriatedRetainedEarningsIncludingReserveAmortization
TOTAL Appropriated Retained Earnings (Accounts 215, 215.1) (Total of lines of 16 and 18)
20
RetainedEarnings
TOTAL Retained Earnings (Accounts 215, 215.1, 216) (Total of lines 14 and 19)
1,761,598,593
1,662,455,417
21
UnappropriatedUndistributedSubsidiaryEarningsAbstract
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account 216.1)
ReportOnlyOnAnAnnualBasisNoQuarterlyAbstract
Report only on an Annual Basis no Quarterly
22
UnappropriatedUndistributedSubsidiaryEarnings
Balance-Beginning of Year (Debit or Credit)
163,556
3,671,747
23
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings for Year (Credit) (Account 418.1)
661,385
3,835,303
24
DividendsReceived
(Less) Dividends Received (Debit)
25
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
Other Changes (Explain)
25.1
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
Other Changes (Explain)
26
UnappropriatedUndistributedSubsidiaryEarnings
Balance-End of Year
497,829
163,556


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DividendsDeclaredCommonStock

 

CASH DISTRIBUTION

$

490,000,000

INCOME TAX DISTRIBUTION

 

(6,148,000)

SUBSIDIARY INCOME TAX DISTRIBUTION

 

(632,000)

TOTAL DISTRIBUTION FROM RETAINED EARNINGS

$

483,220,000

(b) Concept: DividendsDeclaredCommonStock

 

CASH DISTRIBUTION

$

430,000,000

SUBSIDIARY INCOME TAX DISTRIBUTION

 

(2,088,801)

TOTAL DISTRIBUTION FROM RETAINED EARNINGS

$

427,911,199


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
Statement of Cash Flows
  1. Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc.
  2. Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
  3. Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
  4. Investing Activities: Include at Other (line 25) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.
Line No.
Description (See Instructions for explanation of codes)
(a)
Current Year to Date Quarter/Year
(b)
Previous Year to Date Quarter/Year
(c)
1
NetCashFlowFromOperatingActivitiesAbstract
Net Cash Flow from Operating Activities
2
NetIncomeLoss
Net Income (Line 78(c) on page 114)
583,024,561
370,646,932
3
NoncashChargesCreditsToIncomeAbstract
Noncash Charges (Credits) to Income:
4
DepreciationAndDepletion
Depreciation and Depletion
326,337,818
282,015,729
5
NoncashAdjustmentsToCashFlowsFromOperatingActivities
Amortization of (Specify) (footnote details)
5.1
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Amortization of (Specify) (footnote details)
(a)
1,749,182
(p)
1,379,463
6
DeferredIncomeTaxesNet
Deferred Income Taxes (Net)
36,842,933
260,602,546
7
InvestmentTaxCreditAdjustmentsNet
Investment Tax Credit Adjustments (Net)
8
NetIncreaseDecreaseInReceivablesOperatingActivities
Net (Increase) Decrease in Receivables
(b)
28,947,756
(q)
25,676,885
9
NetIncreaseDecreaseInInventoryOperatingActivities
Net (Increase) Decrease in Inventory
(c)
27,820,542
(r)
13,683,594
10
NetIncreaseDecreaseInAllowancesInventoryOperatingActivities
Net (Increase) Decrease in Allowances Inventory
11
NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
5,890,679
430,171
12
NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Net (Increase) Decrease in Other Regulatory Assets
(d)
7,208,075
(s)
57,221,827
13
NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities
Net Increase (Decrease) in Other Regulatory Liabilities
11,000,506
24,894,595
14
AllowanceForOtherFundsUsedDuringConstructionOperatingActivities
(Less) Allowance for Other Funds Used During Construction
87,110,999
69,653,114
15
UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities
(Less) Undistributed Earnings from Subsidiary Companies
2,338,615
10,335,303
16
OtherAdjustmentsToCashFlowsFromOperatingActivities
Other Adjustments to Cash Flows from Operating Activities
16.1
OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Other (footnote details):
(e)
50,470,846
(t)
48,591,683
18
NetCashProvidedByUsedInOperatingActivities
Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 16)
854,786,410
859,167,848
20
CashFlowsFromInvestmentActivitiesAbstract
Cash Flows from Investment Activities:
21
ConstructionAndAcquisitionOfPlantIncludingLandAbstract
Construction and Acquisition of Plant (including land):
22
GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Gross Additions to Utility Plant (less nuclear fuel)
(f)
1,782,091,487
(u)
1,509,318,517
23
GrossAdditionsToNuclearFuelInvestingActivities
Gross Additions to Nuclear Fuel
24
GrossAdditionsToCommonUtilityPlantInvestingActivities
Gross Additions to Common Utility Plant
25
GrossAdditionsToNonutilityPlantInvestingActivities
Gross Additions to Nonutility Plant
26
AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
(Less) Allowance for Other Funds Used During Construction
(g)
87,110,999
(v)
69,653,114
27
OtherConstructionAndAcquisitionOfPlantInvestmentActivities
Other Construction and Acquisition of Plant, Investment Activities
27.1
OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription
Other (footnote details):
28
CashOutflowsForPlant
Cash Outflows for Plant (Total of lines 22 thru 27)
(h)
1,694,980,488
(w)
1,439,665,403
30
AcquisitionOfOtherNoncurrentAssets
Acquisition of Other Noncurrent Assets (d)
31
ProceedsFromDisposalOfNoncurrentAssets
Proceeds from Disposal of Noncurrent Assets (d)
33
InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Investments in and Advances to Associated and Subsidiary Companies
(i)
3,668,851,455
(x)
2,448,140,153
34
ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies
Contributions and Advances from Associated and Subsidiary Companies
36
DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
(j)
4,142,172,354
(y)
2,829,664,150
38
PurchaseOfInvestmentSecurities
Purchase of Investment Securities (a)
(k)
24,131,905
(z)
25,663,838
39
ProceedsFromSalesOfInvestmentSecurities
Proceeds from Sales of Investment Securities (a)
40
LoansMadeOrPurchased
Loan Made or Purchased
41
CollectionsOnLoans
Collections on Loans
43
NetIncreaseDecreaseInReceivablesInvestingActivities
Net (Increase) Decrease in Receivables
44
NetIncreaseDecreaseInInventoryInvestingActivities
Net (Increase) Decrease in Inventory
45
NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities
Net (Increase) Decrease in Allowances Held for Speculation
46
NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
268,733,744
238,331,689
47
OtherAdjustmentsToCashFlowsFromInvestmentActivities
Other Adjustments to Cash Flows from Investment Activities:
47.1
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Other (footnote details):
(l)
19,397,660
(aa)
4,229,900
49
CashFlowsProvidedFromUsedInInvestmentActivities
Net Cash Provided by (Used in) Investing Activities (Total of lines 28 thru 47)
1,495,127,578
841,243,655
51
CashFlowsFromFinancingActivitiesAbstract
Cash Flows from Financing Activities:
52
ProceedsFromIssuanceAbstract
Proceeds from Issuance of:
53
ProceedsFromIssuanceOfLongTermDebtFinancingActivities
Proceeds from Issuance of Long-Term Debt (b)
993,440,000
54
ProceedsFromIssuanceOfPreferredStockFinancingActivities
Proceeds from Issuance of Preferred Stock
55
ProceedsFromIssuanceOfCommonStockFinancingActivities
Proceeds from Issuance of Common Stock
56
OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Net Increase in Debt (Long Term Advances)
56.1
DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Other (footnote details):
(m)
380,121,168
(ab)
409,987,006
56.2
DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Other (footnote details):
57
NetIncreaseInShortTermDebt
Net Increase in Short-term Debt (c)
59
CashProvidedByOutsideSources
Cash Provided by Outside Sources (Total of lines 53 thru 58)
1,373,561,168
409,987,006
61
PaymentsForRetirementAbstract
Payments for Retirement
62
PaymentsForRetirementOfLongTermDebtFinancingActivities
Payments for Retirement of Long-Term Debt (b)
(n)
250,000,000
63
PaymentsForRetirementOfPreferredStockFinancingActivities
Payments for Retirement of Preferred Stock
64
PaymentsForRetirementOfCommonStockFinancingActivities
Payments for Retirement of Common Stock
65
OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Other Retirements
65.1
DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities
Other (footnote details):
66
NetDecreaseInShortTermDebt
Net Decrease in Short-Term Debt (c)
67
OtherAdjustmentsToCashFlowsFromFinancingActivities
Other Adjustments to Financing Cash Flows
68
DividendsOnPreferredStock
Dividends on Preferred Stock
69
DividendsOnCommonStock
Dividends on Common Stock
(o)
483,220,000
(ac)
427,911,199
70
CashFlowsProvidedFromUsedInFinancingActivities
Net Cash Provided by (Used in) Financing Activities (Total of lines 59 thru 69)
640,341,168
17,924,193
73
NetIncreaseDecreaseInCashAndCashEquivalentsAbstract
Net Increase (Decrease) in Cash and Cash Equivalents
74
NetIncreaseDecreaseInCashAndCashEquivalents
(Total of line 18, 49 and 71)
76
CashAndCashEquivalents
Cash and Cash Equivalents at Beginning of Period
78
CashAndCashEquivalents
Cash and Cash Equivalents at End of Period


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities

 

DEBT DISCOUNT AND EXPENSE

(b) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: -28947756
(c) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: -27820542
(d) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -7208075
(e) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

 

 

ASSET RETIREMENT OBLIGATION REMOVAL COSTS

$

(9,416,060)

NET TRANSPORTATION AND EXCHANGE RECEIVABLE IMBALANCE

 

2,541,973

POTENTIAL ASSESSMENTS

 

(200,000)

ACCRUED INSURANCE

 

16,242

SPECIAL DEPOSITS

 

396,844

CUSTOMER DEPOSITS

 

20,645,590

DEFERRED REGULATORY COMMISSION EXPENSE

 

(459,489)

PREPAYMENTS

 

1,385

PREPAID FIRM TRANSPORTATION

 

(965,790)

SUSPENSE PROJECTS

 

(3,918,327)

CLEARING

 

(1,125,279)

ASSET RETIREMENT OBLIGATION

 

33,674,092

LGA/LGS STORAGE PRICE DIFFERENTIAL

 

(217,340)

ACCRUED ENVIRONMENTAL COSTS

 

(528,000)

(GAIN) LOSS ON INVESTMENTS

 

9,240,019

OTHER, NET

 

784,986

 

$

50,470,846

(f) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -1782091487
(g) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -87110999
(h) Concept: CashOutflowsForPlant
Original value: -1694980488
(i) Concept: InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Original value: -3668851455
(j) Concept: DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies

 

REPAYMENT OF NOTE ADVANCES

(k) Concept: PurchaseOfInvestmentSecurities
Original value: -24131905
(l) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

 

NET RETIREMENTS

$

(26,225,503)

CONTRIBUTIONS AND ADVANCES FOR CONSTRUCTION COSTS

 

45,710,291

OTHER, NET

 

(87,128)

 

$

19,397,660

(m) Concept: OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities

 

CAPITAL CONTRIBUTION FROM WILLIAMS PARTNERS OPERATING, LLC (WPO)

$

340,000,000

DEBT ISSUE COSTS

 

(10,147,836)

PROCEEDS FROM LEASE OBLIGATION

 

50,269,004

 

$

380,121,168

(n) Concept: PaymentsForRetirementOfLongTermDebtFinancingActivities
Original value: -250000000
(o) Concept: DividendsOnCommonStock
Original value: -483220000
(p) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities

 

 

DEBT DISCOUNT AND EXPENSE

$

1,338,868

 

LOSS ON REACQUIRED DEBT

 

40,595

 

 

$

1,379,463

(q) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: -25676885
(r) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: 13683594
(s) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -57221827
(t) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

 

 

ASSET RETIREMENT OBLIGATION REMOVAL COSTS

$

(4,578,337)

NET TRANSPORTATION AND EXCHANGE RECEIVABLE IMBALANCE

 

(5,111,024)

POTENTIAL ASSESSMENTS

 

395,400

ACCRUED INSURANCE

 

(1,016,913)

SPECIAL DEPOSITS

 

(58,989)

CUSTOMER DEPOSITS

 

(31,294,999)

DEFERRED REGULATORY COMMISSION EXPENSE

 

(90,836)

PREPAYMENTS

 

948,204

PREPAID FIRM TRANSPORTATION

 

(965,790)

SUSPENSE PROJECTS

 

162,947

CLEARING

 

800,350

ASSET RETIREMENT OBLIGATION

 

103,105,214

LGA/LGS STORAGE PRICE DIFFERENTIAL

 

(1,315,854)

ACCRUED ENVIRONMENTAL COSTS

 

(195,000)

(GAIN) LOSS ON INVESTMENTS

 

(12,559,324)

OTHER, NET

 

366,634

 

$

48,591,683

(u) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -1509318517
(v) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -69653114
(w) Concept: CashOutflowsForPlant
Original value: -1439665403
(x) Concept: InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Original value: -2448140153
(y) Concept: DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies

 

REPAYMENT OF NOTE ADVANCES

(z) Concept: PurchaseOfInvestmentSecurities
Original value: -25663838
(aa) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

 

NET RETIREMENTS

$

(49,089,657)

CONTRIBUTIONS AND ADVANCES FOR CONSTRUCTION COSTS

 

50,119,559

INSURANCE PROCEEDS

 

3,200,000

OTHER, NET

 

(2)

 

$

4,229,900

(ab) Concept: OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities

 

CAPITAL CONTRIBUTION FROM WPO

$ 410,000,000

DEBT ISSUE COSTS

(12,994)

 

$ 409,987,006

(ac) Concept: DividendsOnCommonStock
Original value: -427911199

Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Notes to Financial Statements
  1. Provide important disclosures regarding the Balance Sheet, Statement of Income for the Year, Statement of Retained Earnings for the Year, and Statement of Cash Flow, or any account thereof. Classify the disclosures according to each financial statement, providing a subheading for each statement except where a disclosure is applicable to more than one statement. The disclosures must be on the same subject matters and in the same level of detail that would be required if the respondent issued general purpose financial statements to the public or shareholders.
  2. Furnish details as to any significant contingent assets or liabilities existing at year end, and briefly explain any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or a claim for refund of income taxes of a material amount initiated by the utility. Also, briefly explain any dividends in arrears on cumulative preferred stock.
  3. Furnish details on the respondent's pension plans, post-retirement benefits other than pensions (PBOP) plans, and post-employment benefit plans as required by instruction no. 1 and, in addition, disclose for each individual plan the current year's cash contributions. Furnish details on the accounting for the plans and any changes in the method of accounting for them. Include details on the accounting for transition obligations or assets, gains or losses, the amounts deferred and the expected recovery periods. Also, disclose any current year's plan or trust curtailments, terminations, transfers, or reversions of assets. Entities that participate in multiemployer postretirement benefit plans (e.g. parent company sponsored pension plans) disclose in addition to the required disclosures for the consolidated plan, (1) the amount of cost recognized in the respondent’s financial statements for each plan for the period presented, and (2) the basis for determining the respondent’s share of the total plan costs.
  4. Furnish details on the respondent’s asset retirement obligations (ARO) as required by instruction no. 1 and, in addition, disclose the amounts recovered through rates to settle such obligations. Identify any mechanism or account in which recovered funds are being placed (i.e. trust funds, insurance policies, surety bonds). Furnish details on the accounting for the asset retirement obligations and any changes in the measurement or method of accounting for the obligations. Include details on the accounting for settlement of the obligations and any gains or losses expected or incurred on the settlement.
  5. Provide a list of all environmental credits received during the reporting period.
  6. Provide a summary of revenues and expenses for each tracked cost and special surcharge.
  7. Where Account 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these item. See General Instruction 17 of the Uniform System of Accounts.
  8. Explain concisely any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
  9. Disclose details on any significant financial changes during the reporting year to the respondent or the respondent's consolidated group that directly affect the respondent's gas pipeline operations, including: sales, transfers or mergers of affiliates, investments in new partnerships, sales of gas pipeline facilities or the sale of ownership interests in the gas pipeline to limited partnerships, investments in related industries (i.e., production, gathering), major pipeline investments, acquisitions by the parent corporation(s), and distributions of capital.
  10. Explain concisely unsettled rate proceedings where a contingency exists such that the company may need to refund a material amount to the utility's customers or that the utility may receive a material refund with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency relates and the tax effects and explain the major factors that affect the rights of the utility to retain such revenues or to recover amounts paid with respect to power and gas purchases.
  11. Explain concisely significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and summarize the adjustments made to balance sheet, income, and expense accounts.
  12. Explain concisely only those significant changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also give the approximate dollar effect of such changes.
  13. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
  14. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
  15. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

Transco was indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which was consolidated by The Williams Companies, Inc. (Williams). On August 10, 2018, Williams completed a merger with WPZ, pursuant to which Williams acquired all of the publicly held outstanding common units of WPZ in exchange for shares of Williams' common stock (WPZ Merger). Williams continued as the surviving entity. Transco is now indirectly owned by Williams.

In this report, Transco is at times referred to in the first person as “we,” “us” or “our.”

Transco is a single member limited liability company, and as such, single member losses are limited to the amount of its investment.

Related Party Transaction

A former member of Williams' Board of Directors, who was elected in 2013 and resigned during 2016, is also the current chairman, president, and chief executive officer of Public Service Enterprise Group, an energy services company that is a customer of ours. This board member does not have any material interest in any transactions between the energy services company and us and he had no role in any such transactions.

Nature of Operations

We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the 12 southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, Washington D.C., Maryland, North Carolina, New York, New Jersey and Pennsylvania.

Basis of Presentation

These financial statements were prepared in accordance with the accounting requirements of the Federal Energy Regulatory Commission (FERC) as set forth in its Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than generally accepted accounting principles (GAAP). As a result, the following disclosure may not be consistent with the disclosure in the consolidated financial statements included in the Annual Report on Form 10-K. We have evaluated subsequent events through the date our financial statements were available to be issued on April 12, 2019.

The most significant difference between GAAP and the financial statements presented herein are: (i) the deferral of certain costs and revenues, (ii) the classification of certain accounts in our financial statements, (iii) subsidiaries are reflected under the equity method whereas GAAP requires that all controlled subsidiaries be consolidated, (iv) the inclusion and classification of income taxes in a partnership’s or limited liability company’s financial statements, (v) purchase price allocations related to the acquisition of Transco by Williams in 1995.

The acquisition of Transco by Williams was accounted for using the purchase method of accounting and an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. However, our purchase price allocation assigned to property, plant and equipment and the related adjustments to deferred taxes and amortization are not reflected in the FERC financial statements included herein.

Use of Estimates

The preparation of financial statements in conformity with the FERC regulatory basis of accounting requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; 6) asset retirement obligations; and 7) deferred and other income taxes.

Revenue Recognition (subsequent to the adoption of ASC 606)

Our customers are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical power generators.

A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the product or service is separately identifiable from other items in the integrated package of services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. Service revenue contracts contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. As a rate-regulated entity applying Topic 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of Accounting Standards Update (ASU) 2014-09, Revenues from Contracts with Customers (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset.

Service Revenues

We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or as negotiated with our customers, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one-month periods or less. Our performance obligations include the following:

  • Firm transportation or storage under firm transportation and storage contracts - an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;

    • Interruptible transportation and storage under interruptible transportation and storage contracts - an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.

In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Product Sales

In the course of providing transportation services to customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs. Revenue is recognized from the sale of natural gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note).

Contract Liabilities

Our contract liability consists of an advance payment from a customer for which future service is to be provided under the contract. This amount has been deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily straight-line over the remaining contractual service periods, and is classified as current or non-current according to when such amounts are expected to be recognized.

Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer and when the customer pays for those goods or services and the prevailing interest rates. We have assessed our contracts and determined none of our contracts contain a significant financing component.

Revenue Recognition (prior to the adoption of ASC 606)

Revenues for transportation of gas under long-term firm agreements are recognized considering separately the reservation and commodity charges. Reservation revenues are recognized monthly over the term of the agreement regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point. Revenues for the storage of gas under firm agreements are recognized considering separately the reservation, capacity, and injection and withdrawal charges. Reservation and capacity revenues are recognized monthly over the term of the agreement regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided in our FERC tariff. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note).

As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks.

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. The FERC identifies installation, construction and replacement costs that are to be capitalized. All other costs are expensed as incurred. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income.

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2018 and 2017 are as follows:

Category of Property

 

2018-2017

 

 

 

Gathering facilities

 

1.35% - 2.50%

Storage facilities

 

2.10% -  2.25%

Onshore transmission facilities

 

2.61%  -  5.00%

Offshore transmission facilities

 

1.20%  -  1.20%

We record a liability and increase the basis in the underlying asset for the present value of each expected future ARO at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of these costs in rates.

 

 

Impairment of Long-lived Assets

We evaluate the long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of a potential impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize.

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $29.2 million, and $22.4 million for 2018, and 2017, respectively. The allowance for equity funds was $87.1 million, and $69.7 million, for 2018, and 2017 respectively.

Income Taxes

Williams and its wholly-owned subsidiaries, which includes us, file a consolidated federal income tax return. It is Williams’ policy to charge or credit its taxable subsidiaries with an amount equivalent to their federal income tax expense or benefit computed as if each subsidiary had filed a separate return.

As a limited liability company, Transco is no longer a taxable entity for income tax purposes; however, amounts equivalent to current and deferred income tax expense based on corporate tax rates are presented in the accompanying financial statements since income taxes are a cost component for Transco’s currently effective rates.

We use the assets and liability method of accounting for income taxes, which requires, among other things, provisions for all temporary differences between the financial basis and the tax basis in our assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates. Future cash distributions to member will be allocated between income taxes payable by member and equity distribution and will be recorded as a reduction to income taxes payable and equity based on that allocation.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of determination.

Gas Imbalances

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three-year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2018 and 2017. We utilize the average cost method of accounting for gas imbalances.

Deferred Cash Out

Most transportation imbalances are settled in cash on a monthly basis (cash-out). In accordance with our tariff, revenues received from the cash-out of transportation imbalances in excess of costs incurred are deferred and offset by the deferral of costs incurred in excess of revenues received. At the end of each annual August through July reporting period, if the cumulative revenues received exceed the costs incurred, the over recovered amounts are refunded. If the cumulative revenues received are less than the costs incurred, the net under recovered amounts are carried forward and offset against any future net over recoveries that may occur in a subsequent annual reporting period.

Gas Inventory

We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. At December 31, 2018 and 2017, Gas in Storage, at LIFO, was zero. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost.

Materials and Supplies Inventory

All inventories are stated at average cost. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2018 and 2017.

Contingent Liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable, and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

Pension and Other Postretirement Benefits

We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 8.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost.

Cash Flows from Operating Activities and Cash Equivalents

We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents.

Accounting Standards Issued and Adopted

Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). Among other things, ASU 2016-15 permits an accounting policy election to classify distributions received from equity-method investees using either the cumulative earnings approach or the nature of distribution approach. We have elected to apply the nature of distribution approach and have retrospectively conformed the prior year presentation within the Statement of Cash Flows in accordance with ASU 2016-15. For the period ended December 31, 2017, the amount previously presented as Associated and Subsidiary Companies within Investing Activities is presented as part of (Less) Undistributed Earnings from Subsidiary Companies within Operating Activities, resulting in an increase to Net Cash Provided by (Used in) Operating Activities of $6.5 million with a corresponding reduction in Net Cash Provided by (Used in) Investing Activities.

In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard became effective for interim and annual reporting periods beginning after December 15, 2017.

We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not completed as of that date. There was no cumulative effect adjustment to retained earnings upon initially applying ASC 606 for periods prior to January 1, 2018.

For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. As a result of the adoption of ASC 606, there are no changes to the timing of our revenue recognition or differences in the presentation in our financial statements from those under the previous revenue standard. (See Note 2.)

Accounting Standards Issued But Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13 "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking "expected loss" model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The standard requires varying transition methods for the different categories of amendments. We do not expect ASU 2016-13 to have a significant impact on our financial statements.

In February 2016, the FASB issued ASU 2016-02 "Leases (Topic 842)" (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842" (ASU 2018-01). Per ASU 2018-01, land easements and right-of-way are required to be assessed under ASU 2016-02 to determine whether the arrengements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 "Leases".

On December 27, 2018, the FERC issued Docket No. Al19-1-000 “Accounting and Financial Reporting for Leases” (the Docket). The purpose of the Docket was to provide clarity on how accounting and reporting requirements should be reported for operating leases based on the definition in ASU 2016-02 for regulatory reporting with the FERC. The Docket notes that an entity may choose to record the right of use assets with corresponding lease obligations in the FERC balance sheet accounts established for capital leases. We will not elect to record the right of use assets and corresponding lease obligations with respect to operating leases based on the definition in ASU 2016-02 in the respective capital lease FERC balance sheet accounts.

 

 

 

 

 

 

 

 

2. REVENUE RECOGNITION

Revenue by Category

Our revenue disaggregation by major service line includes Natural gas sales, Natural gas transportation, Natural gas storage, and Other, which are included in Gas Operating Revenues on the Statement of Income.

Contract Liabilities

Our contract liability consists of an advance payment from a customer for which future service is to be provided under the contract. This amount has been deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily straight-line over the remaining contractual service periods and is classified as current or non-current according to when such amounts are expected to be recognized.

The following table presents a reconciliation of our contract liabilities:

 

December 31, 2018

 

(Thousands)

Balance at beginning of period

$

11,838

 

Payments received and deferred

 

Recognized in revenue

(966

)

Balance at end of period

$

10,872

 

The following table presents the amount of the contract liabilities balance as of December 31, 2018, expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:

 

(Thousands)

2019

$

966

 

2020

968

 

2021

966

 

2022

966

 

2023

966

 

Thereafter

6,040

 

 

 

 

 

 

 

 

Remaining Performance Obligations

The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2018. These primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes the variable consideration component for commodity charges. It also excludes consideration that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). As noted above, certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligation as of December 31, 2018, does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.

 

 

(Thousands)

2019

$

2,085,113

 

2020

1,956,772

 

2021

1,881,776

 

2022

1,520,358

 

2023

1,386,290

 

Thereafter

12,501,777

 

Total

$

21,332,086

 

Accounts Receivable

Receivables from contracts with customers are included within Customer Accounts Receivable, and receivables that are not related to contracts with customers are included with Other Accounts Receivable and Accounts Receivable from Associated Companies in our Balance Sheet.

3. RATE AND REGULATORY MATTERS

Rate Matters

General rate case (Docket No. RP18-1126) On August 31, 2018, we filed a general rate case with the FERC for an overall increase in rates and to comply with the terms of the settlement in our prior rate case to file a rate case no later than August 31, 2018. On September 28, 2018, the FERC issued an order accepting and suspending our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing, except that rates for certain services that were proposed as overall rate decreases were accepted, without suspension, to be effective October 1, 2018. The decreased rates will not be subject to refund but may be subject to decrease prospectively under Section 5 of the Natural Gas Act of 1938, as amended. On March 18, 2019, the FERC accepted our motion to place the rates that were suspended by the September 28, 2018 order into effect on March 1, 2019, subject to refund.

 

 

Regulatory Accounting

In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent. We have recognized a regulatory liability to reflect the probable return to certain customers through future rates of the future decrease in income taxes payable associated with Tax Reform. The liability was recorded in December 2017 through a regulatory charge to operating income of $840.4 million, and this regulatory charge was reduced by $36.4 million in 2018 mostly due to an updated weighted average state income tax rate. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service.

Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity in earnings of subsidiary companies on our Statement of Income has been reduced by $2.0 million and $10.3 million in 2018 and 2017, respectively, related to our proportionate share of the associated regulatory charges.

Our regulatory asset associated with the effects of deferred taxes on equity funds used during construction was also impacted by Tax Reform and was increased by $4.8 million and reduced by $109.9 million in 2018 and 2017, respectively.

As a result of the WPZ Merger in August 2018, we also recorded an $85.2 million regulatory state tax asset associated with an increase in our estimated state income tax rate. We are still in the process of finalizing our valuation of the WPZ assets (See Note 9).

On March 15, 2018, the FERC issued a revised policy statement (the March 15 Statement) in Docket No. PL17-1 regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit a MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the WPZ Merger is to allow us to continue to recover an income tax allowance in our cost of service rates.

On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these previously accumulated ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the March 15 Statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the fact of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC's guidance on ADIT likely will be challenged by customers and state commission, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.

On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking in Docket No. RM18-11 proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the corporate income tax rate in Tax Reform and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule in the docket, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. FERC also clarified that a natural gas company organized as a pass-through entity all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax, and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in our rates. Our Docket No. RP18-1126 rate case filing (discussed above) reflects a tax allowance based on this clarification, and the FERC's September 28, 2018 order in that rate case proceeding finds that we are exempt from the FERC Form No. 501-G filing requirement established in Docket No. RM18-11.

On March 15, 2018, the FERC also issued a Notice of Inquiry in Docket No. RM18-12 seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that our future tariff-based rates collected may be adversely impacted.

4. CONTINGENT LIABILITIES

Station 62 Incident

On October 8, 2015, an explosion and fire occurred at our Compressor Station No. 62 in Gibson, Louisiana. At the time of the incident, planned facility maintenance was being performed at the station and the facility was not operational. The incident was related to maintenance work being performed on the slug catcher at the station. Four contractor employees were killed in the incident and others were injured.

In responding to the incident, we cooperated with local, state and federal authorities, including the Louisiana State Police, Terrebonne Parish, the Louisiana Department of Environmental Quality, the U.S. Environmental Protection Agency (Region 6), the Occupational Safety and Health Administration, and the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA). On July 29, 2016, PHMSA issued a Notice of Probable Violation (NOPV), which includes a $1.6 million proposed civil penalty to us in connection with the incident. This penalty was accrued in the second quarter of 2016 and would not be covered by our insurance policies. We filed a response to the NOPV on August 25, 2016, and on July 14, 2017, PHMSA held a hearing on the NOPV. On December 20, 2018, the PHMSA issued a Final Order, which made findings of violation, reduced the civil penalty to $1.4 million, and specified actions that need to be taken by us to comply with pipeline safety regulations.

The incident did not cause any rupture of the gas pipeline or any damage to the building containing the compressor engines. In anticipation of the planned maintenance, our Southeast Louisiana Lateral was taken out of service on October 4, 2015, which affected approximately 200 MMcf/d of natural gas production. The lateral was restored to service in early 2016 after repairs were made to the facilities damaged in the incident.

We, with the insurer of one of our contractors, have settled several claims against us for wrongful death and personal injury. In addition, we are a defendant in other lawsuits seeking damages for wrongful death, personal injury and property damages. We believe it is reasonably possible that losses will be incurred on some lawsuits. However, in management's judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations or cash flows. While we also have claims for indemnification, we continue to believe that it is probable that any ultimate losses incurred will be covered by our contractors' insurance and our insurance.

 

 

Environmental Matters

We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $5 million to $7 million (including both expense and capital expenditures), measured on an undiscounted basis, and will substantially be spent over the next four to six years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At December 31, 2018, we had a balance of approximately $3.5 million for the expense portion of these estimated costs, $1.5 million recorded in Miscellaneous Current and Accrued Liabilities and $2.0 million recorded in Other Deferred Credits in the Balance Sheet. At December 31, 2017, we had a balance of approximately $4.0 million for the expense portion of these estimated costs, $1.8 million recorded in Miscellaneous Current and Accrued Liabilities and $2.2 million recorded in Other Deferred Credits in the Balance Sheet.

We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $5 million to $7 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Net Utility Plant in the Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings.

For the year ended December 31, 2018, we purchased the following credits: 3.99 credits from Marsh Resources Mitigation Bank for $933,332 and 0.29 Riparian credits for $478,500 for the Meadows Reliability Enhancement Project; 0.465 acres of forested wetland from the Green Vest – Oradell Reservoir Mitigation Bank for $302,250 for the Paramus, Emerson, Orange and Rockland Stations; 0.67 acres from Marsh Resources Mitigation Bank for $156,333 for the Riverdale South to Market Project; 86 credits for $324,887 for the Atlantic Sunrise Project; and 750 credits for $5,174,925 for the Northeast Supply Enhancement Project.

For the year ended December 31, 2017, we purchased the following environmental credits; 106 credits for $466,268 for the Atlantic Sunrise Expansion project.

Other Matters

Various other proceedings are pending against us and are considered incidental to our operations.

Summary

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.

Other Commitments

Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $137 million at December 31, 2018.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

5. DEBT, FINANCING ARRANGEMENTS AND LEASES

Long-Term Debt

At December 31, 2018 and 2017, long-term debt outstanding was as follows (in thousands):

 

 

2018

 

2017

Debentures:

 

 

 

 

7.08% due 2026

 

$

7,500

 

 

$

7,500

 

7.25% due 2026

 

200,000

 

 

200,000

 

Total debentures

 

207,500

 

 

207,500

 

 

 

 

 

 

Notes:

 

 

 

 

6.05% due 2018

 

 

 

250,000

 

7.85% due 2026

 

1,000,000

 

 

1,000,000

 

4.0% due 2028

 

400,000

 

 

 

5.4% due 2041

 

375,000

 

 

375,000

 

4.45% due 2042

 

400,000

 

 

400,000

 

4.6% due 2048

 

600,000

 

 

 

Total notes

 

2,775,000

 

 

2,025,000

 

 

 

 

 

 

Total long-term debt, including current portion

 

2,982,500

 

 

2,232,500

 

Unamortized debt premium and discount, net

 

(11,137

)

 

(5,043

)

 

 

 

 

 

Total long-term debt

 

$

2,971,363

 

 

$

2,227,457

 

There are no aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2018, and for the next five years.

No property is pledged as collateral under any of our long-term debt issues.

Restrictive Debt Covenants

At December 31, 2018, none of our debt instruments restrict the amount of distributions to our parent, provided, however, that under the credit facility described below, we are restricted from making distributions to our parent during an event of default if we have directly incurred indebtedness under the credit facility. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels and to guarantee certain indebtedness. The indenture governing our $1 billion of 7.85 percent Senior Notes due 2026 further restricts our ability to guarantee certain indebtedness.

Issuance and Retirement of Long-Term Debt

On March 15, 2018, we issued $400 million of 4.0 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private debt placement. We used the net proceeds to repay indebtedness, including our $250 million of 6.05 percent senior unsecured notes due 2018 upon their maturity on June 15, 2018, and for general corporate purposes, including the funding of capital expenditures. The notes were issued under an Indenture, dated as of March 15, 2018 between us and The Bank of New York Mellon Trust Company, N.A., as trustee. As part of the issuance, we entered into a registration rights agreement with the initial purchasers of the notes. Under the terms of the agreement, we were obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act within 365 days after closing and to use commercially reasonable efforts to complete the exchange offer. We filed a registration statement, which was subsequently declared effective by the SEC, and consummated the exchange offer in the third quarter of 2018.

Credit Facility

On July 13, 2018, we, along with Williams and Northwest Pipeline LLC (the “borrowers”), the lenders named therein, and an administrative agent entered into a Credit Agreement with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. We and Northwest are each subject to a $500 million borrowing sublimit. The facility made available under the Credit Agreement is initially available for five years from the Credit Agreement Effective Date (the “Maturity Date”). The borrowers may request an extension of the Maturity Date for an additional one-year period up to two times, to allow a Maturity Date as late as the seventh anniversary of the Credit Agreement Effective Date, subject to certain conditions. The Credit Agreement allows for same day swingline borrowings up to an aggregate amount of $200 million, subject to other utilization of the aggregate commitments under the Credit Agreement. Letter of credit commitments of $1.0 billion are, subject to the $500 million borrowing sublimit applicable to us and Northwest, available to the borrowers. At December 31, 2018 no letters of credit have been issued and loans to Williams of $160 million were outstanding under the credit facility.

Measured as of December 31, 2018, we are in compliance with our financial covenant under the credit facility.

Various covenants may limit, among other things, a borrower's and its material subsidiaries' ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business.

If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies.

Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.'s alternate base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower's senior unsecured long-term debt ratings.

Williams participates in a commercial paper program and Williams management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $4.0 billion of unsecured commercial paper notes. At December 31, 2018, Williams had no outstanding commercial paper.

 

 

 

 

Lease Obligations - Operating

The future minimum lease payments under our various operating leases are as follows (in thousands):

 

2019

 

$

9,044

 

2020

 

9,014

 

2021

 

8,865

 

2022

 

8,808

 

2023

 

8,829

 

Thereafter

 

65,107

 

Total net minimum obligations

 

$

109,667

 

Our lease expense was $10.8 million in 2018 and $11.0 million in 2017.

 

 

Lease Obligations – Capital

The future minimum lease payments under our two capital leases are as follows (in thousands):

 

2019

 

$

121,270

 

2020

 

121,269

 

2021

 

121,270

 

2022

 

121,270

 

2023

 

121,270

 

Thereafter

 

2,046,121

 

Total net minimum obligations

 

$

2,652,470

 

Our lease amortization was $4.8 million in 2018, and $0.6 million in 2017.

In 2017, we recorded a capital lease obligation associated with the Dalton lateral. At December 31, 2017, we had liabilities of $229.3 million in Obligations Under Capital Leases-Noncurrent and $1.6 million in Obligations Under Capital Leases-Current and an asset of $230.9 million in Utility Plant.

During 2018, we received an additional $29.8 million of funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. At December 31, 2018, we had $258.1 million in Obligations Under Capital Leases-Noncurrent and $1.9 million in Obligations Under Capital Leases-Current and an asset of $260.0 million in Utility Plant.

In 2018, we recorded a capital lease obligation associated with the Atlantic Sunrise Project. At December 31, 2018, we had liabilities of $793.8 million in Obligations Under Capital Leases-Noncurrent and $13.5 million included in Obligations Under Capital Leases-Current and an asset of $807.3 million in Utility Plant.

 

6. INVESTMENTS

ARO Trust

We are entitled to collect in rates the amounts necessary to fund our ARO. We deposit monthly, into an external trust account (ARO Trust), the revenues specifically designated for ARO. The ARO Trust carries a moderate risk portfolio. The Money Market Funds held in our ARO Trust are considered investments. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.

Effective March 1, 2013, the annual funding obligation is approximately $36.4 million, with deposits made monthly.

Investments within the ARO Trust at fair value were as follows (in millions):

 

 

 

December 31, 2018

 

December 31, 2017

 

 

Amortized

Cost Basis

 

Fair

Value

 

Amortized

Cost Basis

 

Fair

Value

Money Market Funds

 

$

21.7

 

 

$

21.7

 

 

$

12.6

 

 

$

12.6

 

U.S. Equity Funds

 

46.4

 

 

56.8

 

 

35.9

 

 

50.5

 

International Equity Funds

 

21.9

 

 

21.4

 

 

20.7

 

 

24.6

 

Municipal Bond Funds

 

50.1

 

 

49.6

 

 

46.8

 

 

46.9

 

Total

 

$

140.1

 

 

$

149.5

 

 

$

116.0

 

 

$

134.6

 

 

 

 

 

 

 

 

 

 

 

 

 

7. FAIR VALUE MEASUREMENTS

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of short-term financial assets (Notes Receivable from Associated Companies) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

 

 

 

 

 

 

Fair Value Measurements Using

 

 

 

 

 

 

Quoted

 

 

 

 

 

 

 

 

 

 

Prices In

 

 

 

 

 

 

 

 

 

 

Active

 

Significant

 

 

 

 

 

 

 

 

Market for

 

Other

 

Significant

 

 

 

 

 

 

Identical

 

Observable

 

Unobservable

 

 

Carrying

 

Fair

 

Assets

 

Inputs

 

Inputs

 

 

Amount

 

Value

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

 

 

 

 

 

(Millions)

 

 

 

 

Assets (liabilities) at December 31, 2018:

 

 

 

 

 

 

 

 

 

 

Measured on a recurring basis:

 

 

 

 

 

 

 

 

 

 

ARO Trust investments

$

149.5

$

149.5

$

149.5

$

-

$

-

 

 

 

 

 

 

 

 

 

 

 

Additional disclosures:

 

 

 

 

 

 

 

 

 

 

Long-term debt - including current portion

 

(2,971.4)

 

(3,136.5)

 

-

 

(3,136.5)

 

-

 

 

 

 

 

 

 

 

 

 

 

Assets (liabilities) at December 31, 2017:

 

 

 

 

 

 

 

 

 

Measured on a recurring basis:

 

 

 

 

 

 

 

 

 

 

ARO Trust investments

$

134.6

$

134.6

$

134.6

$

-

$

-

 

 

 

 

 

 

 

 

 

 

 

Additional disclosures:

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

(2,227.5)

 

(2,653.2)

 

-

 

(2,653.2)

 

-

 

 

 

 

 

 

 

 

 

 

 

Fair Value Methods

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

ARO Trust investments - We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and are reported in Other Special Funds on the accompanying Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 6 for more information regarding the ARO Trust.

Long-term debt - The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31, 2018 or 2017.

8. BENEFIT PLANS

Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below.

Pension and Other Postretirement Benefit Plans

Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension costs charged to us by Williams was $12.8 million, and $15.6 million for 2018, and 2017, respectively. Included in our pension costs are settlement charges of $2.7 million and $7.6 million for 2018 and 2017, respectively. These amounts reflect the portion of Williams’ settlement charge directly charged to us which was required as a result of lump-sum benefit payments made under Williams’ program to pay out certain deferred vested pension benefits, as well as lump-sum benefit payments made throughout 2018 and 2017. In addition, we were charged $2.7 million and $4.6 million for 2018 and 2017, respectively, of allocated corporate expenses also associated with the settlement charge.

Williams makes annual cash contributions to the pension plans, based on annual actuarial estimates, which Transco recovers through rates that are set through periodic general rate filings. Effective with the RP12-993 Settlement, any amounts of annual contributions that exceed an upper threshold or fall below a lower threshold are recorded as adjustments to income and collected or refunded through future rate adjustments. The amount of deferred pension collections recorded as a regulatory liability at December 31, 2018 and 2017 were $48.5 million and $32.5 million, respectively.

Williams provides subsidized retiree health care and life insurance benefits to certain eligible participants. Generally, participants that were employed by Williams on or before December 31, 1991 or December 31, 1995, if they were employees or retirees of Transco Energy Company and its subsidiaries, are eligible for subsidized retiree health care benefits. We recognized other postretirement benefit income of $5.9 million, and $10.9 million for 2018, and 2017, respectively.

We have been allowed by rate case settlements to collect or refund in future rates any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to expense and collected or refunded through future rate adjustments. The amount of other postretirement benefits costs deferred as a regulatory liability at December 31, 2018 and 2017 are $79.8 million and $73.9 million, respectively. These amounts are comprised of amounts being deferred for future rate treatment of $73.9 million and $65.4 million at December 31, 2018 and 2017, respectively, and amounts of $5.9 million and $8.5 million being amortized over a period of approximately 8 years per Docket No. RP12-993 at December 31, 2018 and 2017, respectively.

Defined Contribution Plan

Williams maintains a defined contribution plan for substantially all of its employees. Williams charged us compensation expense of $7.9 million and $7.7 million in 2018 and 2017, respectively, for Williams’ company matching contributions to this plan.

Employee Stock-Based Compensation Plan Information

The Williams Companies, Inc. 2007 Incentive Plan, as subsequently amended and restated, (Plan) provides for Williams’ common stock-based awards to both employees and non-management directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets achieved.

Williams currently bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards. We are also billed for our proportionate share of Williams’ and other affiliates’ stock-based compensation expense through various allocation processes.

Total stock-based compensation expense for the years ended December 31, 2018 and 2017 was $6.3 million, $5.7 million, respectively, excluding amounts allocated from WPZ and Williams.

9. INCOME TAXES

Following is a summary of the provision for income taxes for 2018 and 2017 (in thousands):

 

 

2018

 

2017

Current:

 

 

 

 

Federal

$

98,187

$

(30,297)

State

 

26,873

 

(4,549)

 

 

125,060

 

(34,846)

Deferred:

 

 

 

 

Federal

 

55,174

 

276,604

State

 

(18,331)

 

(16,002)

 

 

36,843

 

260,602

Provision for income taxes

$

161,903

$

225,756

Following is a reconciliation of the provision for income taxes at the federal statutory rate to the provision for income taxes (in thousands):

 

 

2018

 

2017

Taxes computed by applying the federal statutory rate

$

156,435

$

208,741

State income taxes (net of federal benefit)

 

92,751

 

(13,358)

State tax rate change regulatory liability

 

(67,300)

 

0

Regulatory asset/liability rate change true-up

 

(23,051)

 

617,691

Federal tax rate change deferred tax impact

 

18,106

 

(567,280)

Regulatory asset Equity AFUDC

 

(12,978)

 

(22,027)

Other, net

 

(2,060)

 

1,989

Provision for income taxes

$

161,903

$

225,756

Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the taxes basis of our assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.

Significant components of deferred income tax liabilities and assets as of December 31, 2018 and 2017 are as follows:

 

 

2018

 

2017

Deferred Tax Liabilities

 

 

 

 

Property, plant and equipment

$

1,324,182

$

1,140,761

Deferred charges

 

5,304

 

5,204

Total Deferred Tax Liabilities

$

1,329,486

$

1,145,965

 

 

 

 

 

Deferred Tax Assets

 

 

 

 

Other Accrued Liabilities

$

101,883

$

88,313

Contingent Liabilities

 

551

 

449

Environmental Liabilities

 

907

 

947

Net Regulatory Liabilities

 

93,693

 

126,752

Other

$

91

$

120

Total Deferred Tax Assets

 

197,125

$

216,581

Net Deferred Tax Liabilities

$

1,132,361

$

929,384

On December 22, 2017, Tax Reform was enacted. Most of the provisions of Tax Reform were effective after January 1, 2018. However, the deferred tax impact of reducing the U.S. corporate tax rate from 35 percent to 21 percent was recognized in the period of enactment. This re-measurement resulted in a reduction of our accumulated deferred income tax (ADIT) for excess ADIT in 190, 282, and 283 accounts. This excess ADIT of approximately $840 million including gross-up to the revenue requirement level was recorded in 2017 with a corresponding increase to a regulatory liability in account 254. This reflects the fact that the excess ADIT will be passed to customers. In 2018, a reduction to this regulatory liability was made for approximately $36 million including gross-up to reflect an updated income tax rate for allocation of our taxable income between corporate and non-corporate taxpayers.

Our lengthy history and use of composite rates for book depreciation over an extended period of time precludes us from having the data necessary to determine the amount of ADIT attributable to protected (depreciation method and life differences) and unprotected ADIT. The excess ADIT recorded in FERC account 254 will be amortized and refunded to customers over time to FERC account 411.1. No reversal occurred in 2018. We have proposed to reverse the excess ADIT, both protected and unprotected using the Reverse South Georgia method. The acceptance of this method and any amortization period is pending settlement of our rate case filing in Docket RP18-1126.

The completion of the WPZ Merger was a taxable exchange to the WPZ unit holders, which results in an adjustment to the tax basis in the underlying assets deemed acquired. At this time the final adjusted tax basis in those assets has not been determined for Transco. Therefore, no adjustment to ADIT has been reflected in these financial statements. However, increased tax depreciation from the additional tax basis will reduce taxable income. The increased tax depreciation based on a preliminary estimate of the additional tax basis has been included in the provision (benefit) for income taxes.

There were no cash payments for income taxes (net of refunds) in 2018 or 2017.

As of December 31, 2018, we had no unrecognized tax benefits. During the next twelve months, we do not expect to have a material impact on our financial position for settlement of any domestic matters under audit.

10. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Major Customers

Operating revenues received from three of our major customers in 2018 and 2017 are as follows (in millions):

 

2018

 

2017

 

Duke Energy Corporation

$

194.5

 

 

$

198.4

 

 

National Grid

186.1

 

177.4

 

The Southern Company, Inc.

166.2

 

 

160.0

 

 

Affiliates

We are a participant in Williams' cash management program, and we make advances to and receive advances from Williams. At December 31, 2018 and 2017, our advances to Williams totaled approximately $33.0 million and $506.4 million, respectively. These advances are represented by demand notes and are classified as Notes Receivable from Associated Companies in the accompanying Balance Sheet. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on Williams' excess cash at the end of each month. At December 31, 2018, the interest rate was 2.24 percent.

Included in Operating Revenues in the accompanying Statement of Income for 2018 and 2017 are revenues received from affiliates of $10.1 million and $10.3 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in Operation Expenses in the accompanying Statement of Income for 2018 and 2017 is purchased gas cost from affiliates of $5.4 million and $3.9 million, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $395.3 million and $370.4 million during 2018 and 2017, respectively, for these services. Such expenses are primarily included in Operation and Maintenance expenses in the accompanying Statement of Income.

We provide services to certain of our affiliates. We recorded reductions in Operating Expenses for services provided to and reimbursed by our affiliates of $4.7 million and $3.7 million in 2018 and 2017, respectively.

We made equity distributions of $483.2 million and $427.9 million during 2018 and 2017, respectively. In January 2019, an additional distribution of $144.8 million was declared and paid.

During 2018 and 2017, our parent made contributions totaling $340 million and $410 million, respectively, to us to fund a portion of our expenditures for additions to property, plant and equipment.

11. ASSET RETIREMENT OBLIGATIONS

These accrued obligations relate to underground storage caverns, offshore platforms, pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.

During 2018 and 2017, our overall asset retirement obligation changed as follows (in thousands):

 

 

2018

 

2017

Beginning balance

 

$

363,956

 

 

$

275,452

 

Accretion (1)

 

32,924

 

 

104,659

 

New obligations

 

14,162

 

 

28,447

 

Changes in estimates of existing obligations (2)

 

(8,054

)

 

(38,470

)

Property dispositions/obligations settled

 

(8,665

)

 

(6,132

)

Ending balance

 

$

394,323

 

 

$

363,956

 

 

(1) The decrease in accretion for 2018 is due to the 2017 cumulative effect of accretion adjustment associated with new AROs identified in our historical land agreements of $87 million that are not a component of new obligations.

(2) Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rate, current estimates for removal cost, discount rates, and the estimated remaining life of assets. The decrease in 2018 is primarily due to a decrease in current estimates for onshore removal costs. The decrease in 2017 is primarily due to a decrease in current estimates for offshore removal costs.

We are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding our ARO. Under our current rate settlement our annual funding obligation is approximately $36.4 million, with installments to be deposited monthly (See Note 6).

 

 

 

 

 

12. REGULATORY ASSETS AND LIABILITIES

The regulatory assets and regulatory liabilities included in the accompanying Balance Sheet at December 31, 2018 and December 31, 2017 are as follows (in millions):

 

Regulatory Assets

 

2018

 

2017

Grossed-up deferred taxes on equity funds used during construction

$

156.8

$

111.2

Asset retirement obligations

 

171.9

 

168.7

Asset retirement costs - Eminence

 

45.5

 

49.5

Deferred taxes - asset

 

87.9

 

3.8

Deferred cash out

 

54.9

 

42.5

Deferred gas costs

 

4.0

 

6.0

Fuel cost

 

61.2

 

61.4

Other

 

-

 

2.1

Total Regulatory Assets

$

582.2

$

445.2

 

Regulatory Liabilities

 

2018

 

2017

Deferred taxes - liability

$

804.0

$

840.4

Sentinel meter station depreciation

 

6.4

 

6.3

Postretirement benefits other than pensions

 

79.8

 

73.9

Electric power cost

 

0.1

 

13.3

Pension – deferred collections

 

48.5

 

32.5

Other

 

2.5

 

0.3

Total Regulatory Liabilities

$

941.3

$

966.7

The significant regulatory assets and liabilities include:

Grossed-up deferred taxes on equity funds used during construction: Regulatory asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. All amounts were generated during the period that we were a taxable entity. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.

Asset retirement obligations: Regulatory asset balance established to offset depreciation of the ARO asset and changes in the ARO liability due to the passage of time. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates (See Note 11).

Asset retirement costs - Eminence: Regulatory asset balance associated with the Eminence Storage Field retirement costs. The regulatory asset is being recovered through our rates and is being amortized to expense consistent with the amounts collected in rates.

Deferred taxes - asset: Regulatory asset balance was established as a result of an increase to rate base deferred taxes due to an increase to the effective state income tax rate. The regulatory asset is being collected from rate payers over the remaining depreciable lives of the long-lived asset to which they relate.

Deferred cash out: This amount represents the deferral of gains or losses on the purchases and sales of gas imbalances with shippers. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual cash out filing periods.

Deferred gas costs: This amount arises from the movement of gas volumes between gas inventory accounts that have different valuations. These amounts are expected to be recovered/refunded in subsequent periods.

Fuel cost: This amount represents the difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual fuel tracker filing periods.

Sentinel meter station depreciation: This amount reflects the incremental depreciation being recorded related to the meter station modifications made for three of the Sentinel shippers. These modifications will be recovered through a surcharge over a defined period of time as stated in the Sentinel FERC order. The incremental depreciation represents the difference between the FERC granted depreciation rate for such facilities in the last rate case as compared to the depreciation rates in the Sentinel order which are based on the contractual terms in the surcharge agreements. The incremental depreciation will be recorded through the end of the contractual term and then will be amortized.

Postretirement benefits: We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any difference between the annual actuarially determined cost and the amount recovered in rates is recorded as a regulatory asset or liability to be collected or refunded through future rate adjustments. These amounts are not included in the rate base (See Note 8).

Electric power cost: This amount represents the difference between the electric power costs recovered from our customers and the electric power costs incurred in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual electric power tracker filing periods.

Pension - deferred collections: We recover the actuarially determined pension cash contributions through rates that are set through periodic general rate filings. Effective with the RP12-993 Settlement, any amounts of annual contributions that exceed an upper threshold or fall below a lower threshold are recorded as adjustments to income and collected or refunded through future rate adjustments (See Note 8).

Deferred taxes - liability: Regulatory liability balance was established as a result of a decrease to rate base deferred taxes due to a decrease to the effective federal income tax rate. The timing of the refund of the regulatory liability to rate payers will be subject to future discussions and negotiations with our customers in our next rate case.

13. SUMMARY OF TRACKED ACTIVITIES

The following is a summary of tracked revenues and expenses for the years 2018 and 2017.

 

 

Annual Charges Adjustment (ACA)

 

2018

 

 

2017

 

 

Revenue

$

5,109,504

 

$

4,524,790

 

 

Expense

 

(4,477,934)

 

 

(4,274,894)

 

 

 

$

631,570

 

$

249,896

 

 

 

 

 

 

 

 

 

 

Tracked Storage

 

 

 

 

 

 

 

Revenue

$

55,426,471

 

$

54,644,329

 

 

Expense

 

(55,293,710)

 

 

(54,843,612)

 

 

 

$

132,761

 

$

(199,283)

 

 

 

 

 

 

 

 

 

 

Electric Power Tracker

 

 

 

 

 

 

 

Revenue

$

21,360,044

 

$

27,541,112

 

 

Expense

 

(34,824,932)

 

 

(20,744,886)

 

 

 

$

(13,464,888)

 

$

6,796,226

 

14. STATEMENT OF CASH FLOW

 

 

2018

 

2017

Account 131 Cash

$ -

 

$ -

Account 135 Working Funds

-

 

-

Cash and Equivalent at End of Year

$ -

 

$ -

 

For the years ended December 31, 2018 and 2017, we paid $168.4 million and $136.4 million, respectively, for the interest (net of amount capitalized).

 

For the years ended December 31, 2018 and 2017, we paid $0.6 million and $2.1 million, respectively, to Williams, for income taxes.



Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization and Depletion
Line No.
Item
(a)
Total Company For the Current Quarter/Year
(b)
Electric
(c)
Gas
(d)
Other (Specify)
(e)
Common
(f)
1
UtilityPlantAbstract
UTILITY PLANT
2
UtilityPlantInServiceAbstract
In Service
3
UtilityPlantInServiceClassified
Plant in Service (Classified)
9,455,218,853
9,455,218,853
4
UtilityPlantInServicePropertyUnderCapitalLeases
Property Under Capital Leases
1,067,285,944
1,067,285,944
5
UtilityPlantInServicePlantPurchasedOrSold
Plant Purchased or Sold
6
UtilityPlantInServiceCompletedConstructionNotClassified
Completed Construction not Classified
5,229,508,090
5,229,508,090
7
UtilityPlantInServiceExperimentalPlantUnclassified
Experimental Plant Unclassified
8
UtilityPlantInServiceClassifiedAndUnclassified
TOTAL Utility Plant (Total of lines 3 thru 7)
15,752,012,887
15,752,012,887
9
UtilityPlantLeasedToOthers
Leased to Others
10
UtilityPlantHeldForFutureUse
Held for Future Use
11
ConstructionWorkInProgress
Construction Work in Progress
563,912,806
563,912,806
12
UtilityPlantAcquisitionAdjustment
Acquisition Adjustments
13
UtilityPlantAndConstructionWorkInProgress
TOTAL Utility Plant (Total of lines 8 thru 12)
16,315,925,693
16,315,925,693
14
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Accumulated Provisions for Depreciation, Amortization, & Depletion
5,644,735,111
5,644,735,111
15
UtilityPlantNet
Net Utility Plant (Total of lines 13 and 14)
10,671,190,582
10,671,190,582
16
DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract
DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17
AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract
In Service:
18
DepreciationUtilityPlantInService
Depreciation
5,538,448,594
5,538,448,594
19
AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService
Amortization and Depletion of Producing Natural Gas Land and Land Rights
20
AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService
Amortization of Underground Storage Land and Land Rights
21
AmortizationOfOtherUtilityPlantUtilityPlantInService
Amortization of Other Utility Plant
106,286,517
106,286,517
22
DepreciationAmortizationAndDepletionUtilityPlantInService
TOTAL In Service (Total of lines 18 thru 21)
5,644,735,111
5,644,735,111
23
DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract
Leased to Others
24
DepreciationUtilityPlantLeasedToOthers
Depreciation
25
AmortizationAndDepletionUtilityPlantLeasedToOthers
Amortization and Depletion
26
DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers
TOTAL Leased to Others (Total of lines 24 and 25)
27
DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract
Held for Future Use
28
DepreciationUtilityPlantHeldForFutureUse
Depreciation
29
AmortizationUtilityPlantHeldForFutureUse
Amortization
30
DepreciationAndAmortizationUtilityPlantHeldForFutureUse
TOTAL Held for Future Use (Total of lines 28 and 29)
31
AbandonmentOfLeases
Abandonment of Leases (Natural Gas)
32
AmortizationOfPlantAcquisitionAdjustment
Amortization of Plant Acquisition Adjustment
33
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
TOTAL Accum. Provisions (Should agree with line 14 above)(Total of lines 22, 26, 30, 31, and 32)
5,644,735,111
5,644,735,111


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Gas Plant in Service (Accounts 101, 102, 103, and 106)
  1. Report below the original cost of gas plant in service according to the prescribed accounts.
  2. In addition to Account 101, Gas Plant in Service (Classified), this page and the next include Account 102, Gas Plant Purchased or Sold, Account 103, Experimental Gas Plant Unclassified, and Account 106, Completed Construction Not Classified-Gas.
  3. Include in column (c) and (d), as appropriate corrections of additions and retirements for the current or preceding year.
  4. Enclose in parenthesis credit adjustments of plant accounts to indicate the negative effect of such accounts.
  5. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c).Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) reversals of tentative distributions of prior year's unclassified retirements. Attach supplemental statement showing the account distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Account 101 and 106 will avoid serious omissions of respondent's reported amount for plant actually in service at end of year.
  6. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102. In showing the clearance of Account 102, include in column (e) the zmounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits to primary account classifications.
  7. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirements of these pages.
  8. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchaser, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give date of such filing.
Line No.
Account
(a)
Balance at Beginning of Year
(b)
Additions
(c)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at End of Year
(g)
1
IntangiblePlantAbstract
INTANGIBLE PLANT
2
OrganizationAbstract
301 Organization
2,387
2,387
3
FranchiseAndConsentsAbstract
302 Franchise and Consents
26,119,068
26,119,068
4
MiscellaneousIntangiblePlantAbstract
303 MiscellaneousIntangiblePlant
28,509,502
276,609
28,232,893
5
IntangiblePlantRollforwardAbstract
Total Intangible Plant (Total of lines 2 thru 4)
54,630,957
276,609
54,354,348
6
ProductionPlantAbstract
PRODUCTION PLANT
7
NaturalGasProductionPlantAbstract
Natural Gas Production and Gathering Plant
8
ProducingLandsRollforwardAbstract
325.1 Producing Lands
9
ProducingLeaseholdsRollforwardAbstract
325.2 Producing Leaseholds
10
GasRightsRollforwardAbstract
325.3 Gas Rights
11
RightsOfWayNaturalGasProductionAndGatheringPlantRollforwardAbstract
325.4 RIghts-of-Way
326,448
326,448
12
OtherLandAndLandRightsRollforwardAbstract
325.5 Other Land and Land Rights
32,211
32,211
13
GasWellStructuresRollforwardAbstract
326 Gas Well Structures
14
FieldCompressorStationStructuresRollforwardAbstract
327 Field Compressor Station Structures
15
FieldMeasuringAndRegulatingStationStructuresRollforwardAbstract
328 Field Measuring and Regulating Station Structures
19,332
4,149
15,183
16
OtherStructuresRollforwardAbstract
329 Other Structures
176,651
176,651
17
ProducingGasWellsWellConstructionRollforwardAbstract
330 Producing Gas Wells-Well Construction
18
ProducingGasWellsWellEquipmentRollforwardAbstract
331 Producing Gas Wells-Well Equipment
19
FieldLinesRollforwardAbstract
332 Field Lines
142,812,896
168,342
142,644,554
20
FieldCompressorStationEquipmentRollforwardAbstract
333 Field Compressor Station Equipment
2,145,314
2,145,314
21
FieldMeasuringAndRegulatingStationEquipmentRollforwardAbstract
334 Field Measuring and Regulating Station Equipment
2,745,585
103,999
23,202
2,826,382
22
DrillingAndCleaningEquipmentRollforwardAbstract
335 Drilling and Cleaning Equipment
23
PurificationEquipmentNaturalGasProductionPlantRollforwardAbstract
336 Purification Equipment
1,038,885
1,038,885
24
OtherEquipmentNaturalGasProductionAndGatheringPlantRollforwardAbstract
337 Other Equipment
25
UnsuccessfulExplorationAndDevelopmentCostsRollforwardAbstract
338 Unsuccessful Exploration and Development Costs
26
AssetRetirementCostsForNaturalGasProductionAndGatheringPlantRollforwardAbstract
339 Asset Retirement Costs for Natural Gas Production and Gathering Plant
6,294,841
1,510,842
787,040
7,018,643
27
NaturalGasProductionAndGatheringPlantAbstract
Total Production and Gathering Plant (Total of lines 8 thru 26)
155,592,163
1,614,841
982,733
156,224,271
28
ProductsExtractionPlantAbstract
PRODUCTS EXTRACTION PLANT
29
LandAndLandRightsProductsExtractionPlantRollforwardAbstract
340 Land and Land Rights
30
StructuresAndImprovementsProductsExtractionPlantRollforwardAbstract
341 Structures and Improvements
31
ExtractionAndRefiningEquipmentRollforwardAbstract
342 Extraction and Refining Equipment
32
PipeLinesRollforwardAbstract
343 Pipe Lines
33
ExtractedProductStorageEquipmentRollforwardAbstract
344 Extracted Products Storage Equipment
34
CompressorEquipmentProductsExtractionPlantRollforwardAbstract
345 Compressor Equipment
35
GasMeasuringAndRegulatingEquipmentRollforwardAbstract
346 Gas Measuring and Regulating Equipment
36
OtherEquipmentProductsExtractionPlantRollforwardAbstract
347 Other equipment
37
AssetRetirementCostsForProductsExtractionPlantRollforwardAbstract
348 Asset Retirement Costs for Products Extraction Plant
38
ProductsExtractionPlantRollforwardAbstract
Total Products Extraction Plant (Total of lines 29 thru 37)
39
NaturalGasProductionPlantRollforwardAbstract
Total Natural Gas Production Plant (Total of lines 27 and 38)
155,592,163
1,614,841
982,733
156,224,271
40
ManufacturedGasProductionPlantAbstract
Manufactured Gas Production Plant (Submit supplementary information in a footnote)
41
NaturalGasProductionPlantAndManufacturedGasProductionPlantRollforwardAbstract
Total Production Plant (Total of lines 39 and 40)
155,592,163
1,614,841
982,733
156,224,271
42
NaturalGasStorageAndProcessingPlantAbstract
NATURAL GAS STORAGE AND PROCESSING PLANT
43
UndergroundStoragePlantAbstract
Underground storage plant
44
LandRollforwardAbstract
350.1 Land
677,235
677,235
45
RightsOfWayNaturalGasStorageAndProcessingPlantRollforwardAbstract
350.2 Rights-of-Way
99,242
99,242
46
StructuresAndImprovementsUndergroundStoragePlantRollforwardAbstract
351 Structures and Improvements
17,178,131
534,231
17,712,362
47
WellsRollforwardAbstract
352 Wells
110,389,255
18,184,238
10,644
128,562,849
48
StorageLeaseholdsAndRightsRollforwardAbstract
352.1 Storage Leaseholds and Rights
5,237,096
5,237,096
49
ReservoirsRollforwardAbstract
352.2 Reservoirs
36,849,971
3,149,181
33,700,790
50
NonrecoverableNaturalGasRollforwardAbstract
352.3 Non-recoverable Natural Gas
4,028,874
4,028,874
51
LinesRollforwardAbstract
353 Lines
24,034,047
593,495
19,939
24,607,603
52
CompressorStationEquipmentUndergroundStoragePlantRollforwardAbstract
354 Compressor Station Equipment
130,539,116
10,840,466
734,395
140,645,187
53
MeasuringAndRegulatingEquipmentUndergroundStoragePlantRollforwardAbstract
355 Measuring and Regulating Equipment
1,376,857
38,720
1,415,577
54
PurificationEquipmentUndergroundStoragePlantRollforwardAbstract
356 Purification Equipment
20,793,323
20,793,323
55
OtherEquipmentUndergroundStoragePlantRollforwardAbstract
357 Other Equipment
1,365,942
10,756
1,355,186
56
AssetRetirementCostsForUndergroundStoragePlantRollforwardAbstract
358 Asset Retirement Costs for Underground Storage Plant
6,950,086
3,005,757
2,584,409
7,371,434
57
UndergroundStoragePlantRollforwardAbstract
Total Underground Storage Plant (Total of lines 44 thru 56)
359,519,175
30,009,006
3,360,143
38,720
386,206,758
58
OtherStoragePlantAbstract
Other Storage Plant
59
LandAndLandRightsOtherStoragePlantRollforwardAbstract
360 Land and Land Rights
1,698,432
1,698,432
60
StructuresAndImprovementsOtherStoragePlantRollforwardAbstract
361 Structures and Improvements
11,433,053
376
11,433,429
61
GasHoldersRollforwardAbstract
362 Gas Holders
10,276,813
10,276,813
62
PurificationEquipmentOtherStoragePlantRollforwardAbstract
363 Purification Equipment
4,029,850
4,029,850
63
LiquefactionEquipmentRollforwardAbstract
363.1 Liquefaction Equipment
2,849,630
67,602
2,917,232
64
VaporizingEquipmentRollforwardAbstract
363.2 Vaporizing Equipment
1,972,746
1,972,746
65
CompressorEquipmentOtherStoragePlantRollforwardAbstract
363.3 Compressor Equipment
39,590,024
2,282,629
2,498
41,870,155
66
MeasuringAndRegulatingEquipmentOtherStoragePlantRollforwardAbstract
363.4 Measuring and Regulating Equipment
131,240
131,240
67
OtherEquipmentOtherStoragePlantRollforwardAbstract
363.5 Other Equipment
417,867
417,867
68
AssetRetirementCostsForOtherStoragePlantRollforwardAbstract
363.6 Asset Retirement Costs for Other Storage Plant
69
OtherStoragePlantRollforwardAbstract
Total Other Storage Plant (Total of lines 58 thru 68)
72,399,655
2,350,607
2,498
74,747,764
70
BaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantAbstract
Base Load Liquefied Natural Gas Terminaling and Processing Plant
71
LandAndLandRightsBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract
364.1 Land and Land Rights
72
StructuresAndImprovementsBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract
364.2 Structures and Improvements
73
LngProcessingTerminalEquipmentRollforwardAbstract
364.3 LNG Processing Terminal Equipment
74
LngTransportationEquipmentRollforwardAbstract
364.4 LNG Transportation Equipment
75
MeasuringAndRegulatingEquipmentBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract
364.5 Measuring and Regulating Equipment
76
CompressorStationEquipmentBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract
364.6 Compressor Station Equipment
77
CommunicationEquipmentBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract
364.7 Communications Equipment
78
OtherEquipmentBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract
364.8 Other Equipment
79
AssetRetirementCostsForBaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract
364.9 Asset Retirement Costs for Base Load Liquefied Natural Gas
80
BaseLoadLiquefiedNaturalGasTerminalingAndProcessingPlantRollforwardAbstract
Total Base Load Liquified Natural Gas , Terminating and Processing Plant (Total of lines 71 thru 79)
81
NaturalGasStorageAndProcessingPlantRollforwardAbstract
Total Nat'l Gas Storage and Processing Plant (Total of lines 57, 69, and 80)
431,918,830
32,359,613
3,362,641
38,720
460,954,522
82
TransmissionPlantAbstract
TRANSMISSION PLAN
83
LandAndLandRightsGasTransmissionPlantRollforwardAbstract
365.1 Land and Land Rights
138,379,033
129,993,788
32,639,545
235,733,276
84
RightsOfWayGasTransmissionPlantRollforwardAbstract
365.2 Rights-of-Way
146,149,898
467,310,742
2,779
613,457,861
85
StructuresAndImprovementsGasTransmissionPlantRollforwardAbstract
366 Structures and Improvements
286,708,038
148,490,250
699,804
1,376,968
435,875,452
86
MainsGasTransmissionPlantRollforwardAbstract
367 Mains
7,470,352,400
1,846,731,487
9,620,514
9,307,463,373
87
CompressorStationEquipmentGasTransmissionPlantRollforwardAbstract
368 Compressor Station Equipment
2,903,585,497
514,400,001
17,426,594
104,440,850
3,504,999,754
88
MeasuringAndRegulatingStationEquipmentRollforwardAbstract
369 Measuring and Regulating Station Equipment
358,092,854
77,014,007
2,157,990
16,956
432,931,915
89
CommunicationEquipmentTransmissionRollforwardAbstract
370 Communication Equipment
90
OtherEquipmentGasTransmissionPlantRollforwardAbstract
371 Other Equipment
157,780,819
1,576,802
1,233,668
73,197,117
81,773,232
91
AssetRetirementCostsForTransmissionPlantTransmissionPlantRollforwardAbstract
372 Asset Retirement Costs for Transmission Plant
14,543,385
1,591,840
543,684
12,407,861
92
TransmissionPlantRollforwardAbstract
Total Transmission Plant (Total of line 81 thru 91)
11,446,505,154
3,183,955,313
30,597,665
35,800
14,599,827,002
93
DistributionPlantAbstract
DISTRIBUTION PLANT
94
LandAndLandRightsGasDistributionPlantRollforwardAbstract
374 Land and Land Rights
95
StructuresAndImprovementsGasDistributionPlantRollforwardAbstract
375 Structures and Improvements
96
MainsGasDistributionPlantRollforwardAbstract
376 Mains
97
CompressorStationEquipmentGasDistributionPlantRollforwardAbstract
377 Compressor Station Equipment
98
MeasuringAndRegulatingStationEquipmentGeneralRollforwardAbstract
378 Measuring and Regulating Station Equipment-General
99
MeasuringAndRegulatingStationEquipmentCityGateCheckStationsRollforwardAbstract
379 Measuring and Regulating Station Equipment-City Gate
100
ServicesRollforwardAbstract
380 Services
101
MetersRollforwardAbstract
381 Meters
102
MeterInstallationsRollforwardAbstract
382 Meter Installations
103
HouseRegulatorsRollforwardAbstract
383 House Regulators
104
HouseRegulatoryInstallationsRollforwardAbstract
384 House Regulator Installations
105
IndustrialMeasuringAndRegulatingStationEquipmentRollforwardAbstract
385 Industrial Measuring and Regulating Station Equipment
106
OtherPropertyOnCustomersPremisesRollforwardAbstract
386 Other Property on Customers' Premises
107
OtherEquipmentGasDistributionPlantRollforwardAbstract
387 Other Equipment
108
AssetRetirementCostsForDistributionPlantDistributionPlantRollforwardAbstract
388 Asset Retirement Costs for Distribution Plant
109
DistributionPlantRollforwardAbstract
Total Distribution Plant (Total of lines 94 thru 108)
110
GeneralPlantAbstract
GENERAL PLANT
111
LandAndLandRightsRollforwardAbstract
389 Land and Land Rights
260,913
260,913
112
StructuresAndImprovementsRollforwardAbstract
390 Structures and Improvements
129,582,672
686,877
27,679
130,241,870
113
OfficeFurnitureAndEquipmentRollforwardAbstract
391 Office Furniture and Equipment
303,694,274
5,703,004
1,990,447
2,920
307,403,911
114
TransportationEquipmentRollforwardAbstract
392 Transportation Equipment
3,648,571
120,269
3,768,840
115
StoresEquipmentRollforwardAbstract
393 Stores Equipment
116
ToolsShopAndGarageEquipmentRollforwardAbstract
394 Tools, Shop, and Garage Equipment
12,402,409
2,311,510
780,968
13,932,951
117
LaboratoryEquipmentRollforwardAbstract
395 Laboratory Equipment
76,782
76,782
118
PowerOperatedEquipmentRollforwardAbstract
396 Power Operated Equipment
6,448,613
178,125
575,668
6,051,070
119
CommunicationEquipmentRollforwardAbstract
397 Communication Equipment
17,715,744
1,216,749
248,302
18,684,191
120
MiscellaneousEquipmentRollforwardAbstract
398 Miscellaneous Equipment
200,283
33,610
1,677
232,216
121
GeneralPlantExcludingOtherTangiblePropertyAndAssetRetirementCostsForGeneralPlantRollforwardAbstract
Subtotal (Total of lines 111 thru 120)
474,030,261
10,250,144
3,624,741
2,920
480,652,744
122
OtherTangiblePropertyRollforwardAbstract
399 Other Tangible Property
123
AssetRetirementCostsForGeneralPlantGeneralPlantRollforwardAbstract
399.1 Asset Retirement Costs for General Plant
124
GeneralPlantRollforwardAbstract
Total General Plant (Total of lines 121, 122, and 123)
474,030,261
10,250,144
3,624,741
2,920
480,652,744
125
GasPlantInServiceAndCompletedConstructionNotClassifiedGasRollforwardAbstract
Total (Accounts 101 and 106)
12,562,677,365
3,228,179,911
38,844,389
15,752,012,887
126
GasPlantPurchasedRollforwardAbstract
Gas Plant Purchased (See Instruction 8)
127
GasPlantSoldRollforwardAbstract
(Less) Gas Plant Sold (See Instruction 8)
128
ExperimentalGasPlantUnclassifiedRollforwardAbstract
Experimental gas plant unclassified
129
GasPlantInServiceRollforwardAbstract
Total Gas Plant In Service (Total of lines 125 thru 128)
12,562,677,365
3,228,179,911
38,844,389
15,752,012,887


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Gas Property and Capacity Leased from Others
  1. Report below the information called for concerning gas property and capacity leased from others for gas operations.
  2. For all leases in which the average annual lease payment over the initial term of the lease exceeds $500,000, describe in column (c), if applicable: the property or capacity leased. Designate associated companies with an asterisk in column (b).
Line No.
LessorName
Name of Lessor
(a)
IndicationOfAssociatedCompany
*
(b)
LeaseDescription
Description of Lease
(c)
GasPropertyAndCapacityLeasePayment
Lease Payments for Current Year
(d)
1
Dogwood Enterprise Holdings, Inc. (Dogwood)
Dogwood's undivided ownership interest in the Dalton Lateral
25,691,000
2
Meade Pipeline CO LLC (Meade)
Meade's undivided joint ownership interest in Central Penn Line
14,645,153
45
Total
40,336,153


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Gas Property and Capacity Leased to Others
  1. For all leases in which the average lease income over the initial term of the lease exceeds $500,000 provide in column (c), a description of each facility or leased capacity that is classified as gas plant in service, and is leased to others for gas operations.
  2. In column (d) provide the lease payments received from others.
  3. Designate associated companies with an asterisk in column (b).
Line No.
LesseeName
Name of Lessee
(a)
IndicationOfAssociatedCompany
*
(b)
LeaseDescription
Description of Lease
(c)
ProceedsFromGasPropertyAndCapacityLeasePayment
Lease Payments for Current Year
(d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
Total


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Gas Plant Held for Future Use (Account 105)
  1. Report separately each property held for future use at end of the year having an original cost of $1,000,000 or more. Group other items of property held for future use.
  2. For property having an original cost of $1,000,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.
GasPlantHeldForFutureUseDescription
Description and Location of Property
(a)
GasPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Date Originally Included in this Account
(b)
GasPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Date Expected to be Used in Utility Service
(c)
GasPlantHeldForFutureUse
Balance at End of Year
(d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
Total


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Construction Work in Progress-Gas (Account 107)
  1. Report below descriptions and balances at end of year of projects in process of construction (Account 107).
  2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstration (see Account 107 of the Uniform System of Accounts).
  3. Minor projects (less than $1,000,000) may be grouped.
Line No.
ConstructionWorkInProgressProjectDescription
Description of Project
(a)
ConstructionWorkInProgress
Construction work in progress - Gas (Account 107)
(b)
ConstructionWorkInProgressEstimatedAdditionalCost
Estimated Additional Cost of Project
(c)
1
APPALACHIAN CONNECTOR EXPANSION
7,669,412
826,332,548
2
ATLANTIC SUNRISE EXPANSION
6,219,558
1,820,632
3
CATHODIC PROTECTION
383,479
1,998,074
4
COMPRESSOR ELECTRICAL EQUIPMENT
3,648,785
2,385,183
5
COMPRESSOR OPERATING SYSTEMS
1,682,313
948,797
6
COMPRESSOR TURBINE EXCHANGES
756
3,080,657
7
COMPRESSOR VALVES
418,654
1,432,867
8
DALTON LATERAL EXPANSION
1,484,457
9
EASTERN INTERSTATE SOFTWARE
1,191,443
2,048,783
10
EMISSIONS REDUCTION PROGRAM
7,472,412
142,121,753
11
FACILITY MODIFICATIONS
8,943,928
30,091,322
12
GATEWAY EXPANSION
17,061,192
67,916,133
13
GULF CONNECTOR EXPANSION
93,452,000
20,591,323
14
HILLABEE EXPANSION PHASE 2
38,408,786
134,079,164
15
HILLABEE EXPANSION PHASE 3
3,957,138
15,547
16
HYDROTEST/REPLACEMENT
7,823,104
47,821,520
17
LEIDY SOUTH EXPANSION
2,487,162
417,367,408
18
LOWER NEW YORK BAY LATERAL STABILIZATION
662,665
2,237,335
19
MEADOWS HEATERS PHASE 2
305,812
5,803,410
20
NORTHEAST SUPPLY ENHANCEMENT
148,708,211
880,477,462
21
OUTSIDE OPERATED UNDERGROUND STORAGE
9,684,750
56,257
22
PIPELINE REPLACEMENT
782,613
4,634,689
23
PIPE SPANS/CROSSINGS
3,480,305
5,730,785
24
PIPE STABILIZATION
567,296
10,008,129
25
PIPELINE PIPE
1,832,131
5,877,575
26
PIPELINE VALVE AUTOMATION
1,336,389
175,689
27
PIPELINE VALVE SPACING
1,257,359
684,495
28
PIPELINE VALVES
7,145,448
37,926,571
29
PURCHASED SOFTWARE
2,941
4,558,548
30
REIMBURSABLE PROJECTS
2,069,175
555,845
31
RIVER VALE SOUTH TO MARKET EXPANSION
19,461,235
89,589,470
32
SAINT JAMES SUPPLY EXPANSION
39,136,197
7,147,800
33
SOUTHEASTERN TRAIL EXPANSION
18,851,521
226,948,472
34
STATION 24 SLUG CATCHER
440,082
31,871,558
35
STATION 240 MODERNIZATION
44,520,824
91,322,018
36
STATION 535 RESTORE
40,347,241
17,529,527
37
UNDERGROUND STORAGE
15,787,373
17,693,689
38
OTHER CONSTRUCTION
5,228,659
3,680,156
45
TOTAL
563,912,806
3,144,561,191


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Non-Traditional Rate Treatment Afforded New Projects
  1. The Commission’s Certificate Policy Statement provides a threshold requirement for existing pipelines proposing new projects is that the pipeline must be prepared to financially support the project without relying on subsidization from its existing customers. See Certification of New Interstate Natural Gas Pipeline Facilities, 88 FERC P61,227 (1999); order clarifying policy, 90 FERC P61,128 (2000); order clarifying policy, 92 FERC P61,094 (2000) (Policy Statement). In column a, list the name of the facility granted non-traditional rate treatment.
  2. In column b, list the CP Docket Number where the Commission authorized the facility.
  3. In column c, indicate the type of rate treatment approved by the Commission (e.g. incremental, at risk)
  4. In column d, list the amount in Account 101, Gas Plant in Service, associated with the facility.
  5. In column e, list the amount in Account 108, Accumulated Provision for Depreciation of Gas Utility Plant, associated with the facility.
  6. In column f, list the amount in Account 190, Accumulated Deferred Income Tax; Account 281, Accumulated Deferred Income Taxes – Accelerated Amortization Property; Account 282, Accumulated Deferred Income Taxes – Other Property; Account 283, Accumulated Deferred Income Taxes – Other, associated with the facility.
  7. In column g, report the total amount included in the gas operations expense accounts during the year related to the facility (Account 401, Operation Expense).
  8. In column h, report the total amount included in the gas maintenance expense accounts during the year related to the facility.
  9. In column i, report the amount of depreciation expense accrued on the facility during the year.
  10. In column j, list any other expenses(including taxes) allocated to the facility.
  11. In column k, report the incremental revenues associated with the facility.
  12. Identify the volumes received and used for any incremental project that has a separate fuel rate for that project.
  13. Provide the total amounts for each column.
Line No.
LocationOrNameOfFacility
Name of Facility
(a)
CPDocketNumber
CP Docket No.
(b)
TypeOfRateTreatment
Type of Rate Treatment
(c)
GasPlantInService
Gas Plant in Service
(d)
AccumulatedProvisionForDepreciationOfGasUtilityPlant
Accumulated Depreciation
(e)
AccumulatedDeferredIncomeTaxes
Accumulated Deferred Income Taxes
(f)
OperationExpense
Operating Expense
(g)
MaintenanceExpense
Maintenance Expense
(h)
DepreciationExpense
Depreciation Expense
(i)
Other Expenses (including taxes)
(j)
Incremental Revenues
(k)
1
SunBelt
CP96-16
Incremental
63,285,010
28,784,056
6,614,889
1,602,357
46,055
191,281
327,797
14,345,095
2
Pocono
CP97-328
Incremental
9,804,384
5,682,412
790,308
20,161
254,765
50,922
1,138,122
3
Cherokee
CP97-331
Incremental
74,692,653
38,297,639
6,978,039
513,773
26,353
1,925,969
386,485
9,359,804
4
MarketLink
CP98-540
Incremental
261,274,546
119,570,601
27,168,986
556,478
23,241
6,918,229
1,357,020
31,055,893
5
SouthCoast
CP99-392
Incremental
94,025,289
44,813,989
9,435,313
372,217
70,625
2,552,075
488,353
14,755,631
6
Sundance
CP00-165
Incremental
109,258,656
44,420,124
12,431,532
308,353
17,084
2,834,399
567,473
20,649,427
7
Leidy East
CP01-389
Incremental
108,043,458
47,586,231
11,591,502
222,309
87
2,905,911
561,161
13,237,606
8
Momentum
CP-01-388
Incremental
170,615,030
64,373,958
20,369,667
457,260
52,767
5,395,514
886,149
28,926,743
9
Trenton Woodbury
CP02-204
Incremental
23,085,975
9,586,301
2,588,301
47,473
599,884
119,905
3,203,238
10
Leidy to Long Island
CP06-34
Incremental
165,564,264
48,116,971
22,518,243
1,340,999
13,874
4,342,183
859,623
26,352,135
11
Potomac
CP06-421
Incremental
75,905,167
21,444,212
10,441,833
156,088
1,972,381
394,240
10,174,199
12
Sentinel
CP08-31
Incremental
242,880,837
59,967,927
35,070,007
500,669
790
6,280,982
1,261,486
32,216,232
13
Eminence Enhancement
CP08-430
Incremental
12,497,513
2,630,150
1,891,876
57,306
93,424
262,980
64,910
2,232,417
14
85 North
CP09-57
Incremental
218,838,683
46,985,304
32,949,556
786,725
327,501
6,787,865
1,136,439
54,720,000
15
Delta
CP09-237
Incremental
367,464
22,419
66,156
15,336
549
12,974
1,909
329,259
16
Pascagoula
CP09-456
Incremental
30,390,881
6,438,593
4,592,387
77,654
789,701
157,846
13,319,958
17
Bayonne
CP09-417
Incremental
1,720,489
126,018
305,709
30,860
48,396
8,936
433,784
18
Mid-South
CP11-18
Incremental
209,657,834
37,857,043
32,939,473
967,553
61,411
5,921,332
1,081,451
46,609,539
19
Northeast Supply Link
CP12-30
Incremental
396,346,895
61,368,478
64,225,622
1,603,049
21,804
11,589,505
2,058,315
54,122,438
20
Northeast Connector
CP13-132
Incremental
53,010,236
6,836,266
8,852,964
133,899
78,062
1,377,623
275,327
9,693,792
21
Virginia Southside
CP13-30
Incremental
288,142,502
31,142,112
49,274,846
926,656
23,551
7,880,879
1,482,643
43,328,034
22
Mobile Bay South lll
CP13-523
Incremental
49,951,229
6,525,394
8,326,063
159,476
8,371
1,678,565
255,598
10,735,461
23
Woodbridge
CP14-18
Incremental
45,390,087
5,193,190
7,706,976
93,338
1,178,055
235,749
5,964,684
24
Rockaway
CP13-36
Incremental
362,352,628
37,945,918
62,198,702
1,435,039
8,630,246
1,600,935
76,400,727
25
Leidy Southeast
CP13-551
Incremental
632,717,975
67,369,932
108,394,534
1,325,546
32,298
20,011,574
3,282,152
111,013,948
26
Rock Springs
CP14-504
Incremental
96,869,421
8,270,360
16,987,153
450,522
126,508
2,536,853
502,195
14,273,202
27
Gulf Trace
CP15-29
Incremental
284,684,857
22,343,739
50,298,827
884,247
749,868
9,399,112
1,477,776
60,223,891
28
Dalton
CP15-117
Incremental
320,133,506
19,669,909
57,608,074
27,250,931
87,947
8,576,080
1,659,616
76,309,789
29
Atlantic Sunrise
CP15-138
Incremental
1,952,020,828
60,873,871
362,590,791
27,282,836
29,182
10,295,982
10,134,018
124,163,717
30
Garden State
CP15-89
Incremental
125,326,197
5,823,994
22,912,232
257,715
2,442,634
649,191
19,519,496
31
New York Bay
CP15-527
(a)
Incremental
110,576,835
6,147,463
20,022,309
227,385
2,754,962
574,319
22,345,537
32
Virginia Southside ll
CP15-118
Incremental
162,119,805
8,416,789
29,469,576
333,375
1,537
4,511,279
784,927
39,928,468
33
Gulf Connector
CP16-494
Incremental
83,251,667
2,205,478
15,539,037
171,195
59,344
431,340
706,333
34
Total
6,834,802,801
976,836,841
1,123,151,483
70,568
37
Gas Plant In Service
13,669,605,602
1,953,673,682
2,246,302,966
70,639,348
1,892,889
142,536,952
35,116,206
991,788,599


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: TypeOfRateTreatment

 

VOLUMES RETAINED UNDER A SEPARATELY STATED FUEL RATE 4,187 Dth


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
General Description of Construction Overhead Procedure
  1. For each construction overhead explain: (a) the nature and extent of work, etc., the overhead charges are intended to cover, (b) the general procedure for determining the amount capitalized, (c) the method of distribution to construction jobs, (d) whether different rates are applied to different types of construction, (e) basis of differentiation in rates for different types of construction, and (f) whether the overhead is directly or indirectly assigned.
  2. Show below the computation of allowance for funds used during construction rates, in accordance with the provisions of Gas Plant Instructions 3 (17) of the Uniform System of Accounts.
  3. Where a net-of-tax rate for borrowed funds is used, show the appropriate tax effect adjustment to the computations below in a manner that clearly indicates the amount of reduction in the gross rate for tax effects.

Construction Overheads

(a) The construction overhead will include certain salaries and expenses directly incidental to specific construction jobs.

(b) The construction overheads are charged directly to a construction overhead clearing work order.

(c) Once construction overheads are charged to a construction clearing work order, they are allocated to specific construction projects.

(d) The same rate is applied to all construction projects.

(e) Not applicable.

(f) The overhead is indirectly assigned.

 

Allowance for Funds Used During Construction Capitalized on Projects in the Process of Construction

1. Allowance for funds used during construction is computed on all classes of property for projects where the construction period is 30 days or more.

2. The means of the current monthly expenditures added to the balance of the previous month (excluding contract retainage and accruals) comprise the base for the computation of the allowance at a rate of 9.00% per annum for the projects.

3. The computation period is from the date costs are first incurred until the facilities are placed in service or ready for service.

4. The AFUDC rate for borrowed funds after compounding is 2.29% and for the other funds after compounding is 6.91%.

COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES

  1. For line (5), column (e) below, enter the rate granted in the last rate proceeding. If not available, use the average rate earned during the preceding 3 years.
  2. Identify in column (c), the specific entity used as the source for the capital structure figures.
  3. Indicate in column (f), if the reported rate of return is one that has been approved in a rate case, black-box settlement rate, or an actual three-year average rate.
1. Components of Formula (Derived from actual book balances and actual cost rates):
Line No.
Title
(a)
Amount
(b)
Entity Name
(c)
Capitalization Ration (percent)
(d)
Cost Rate Percentage
(e)
Rate Indicator
(f)
(1) Average Short-Term Debt
S
(2) Short-Term Interest
s
(3) Long-Term Debt
D
2,227,457,335
33.41
d
6.7
(4) Preferred Stock
P
p
(5) Common Equity
C
4,440,313,533
66.59
c
(a)
10.15
(6) Total Capitaization
6,667,770,868
(7) Average Construction Work in Progress Balance
W
1,569,500,301
2. Gross Rate for Borrowed Funds s(S/W) + d[(D/(D+P+C)) (1-(S/W))] -
2.24
3. Rate for Other Funds [1-(S/W)] [p(P/(D+P+C)) + c(C/(D+P+C))] -
6.76
4. Weighted Average Rate Actually Used for the Year:
(a) Rate for Borrowed Funds -
2.29
(b) Rate for Other Funds -
6.91

Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: CapitalizationOfConstructionOverheadCostRateCommonEquity

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC IS THE ENTITY USED FOR THE CAPITAL STRUCTURE. THE RATE OF RETURN IS AN ACTUAL 3 YEAR AVERAGE RATE.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Accumulated Provision for Depreciation of Gas Utility Plant (Account 108)
  1. Explain in a footnote any important adjustments during year.
  2. Explain in a footnote any difference between the amount for book cost of plant retired, line 10, column (c), and that reported for gas plant in service, page 204-209, column (d), excluding retirements of nondepreciable property.
  3. The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications.
  4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
  5. At lines 7 and 14, add rows as necessary to report all data. Additional rows should be numbered in sequence, e.g., 7.01, 7.02, etc.
Line No.
Item
(a)
Total (c+d+e)
(b)
Gas Plant in Service
(c)
Gas Plant held for Future Use
(d)
Gas Plant Leased to Others
(e)
Section A. BALANCES AND CHANGES DURING YEAR
1
Balance Beginning of Year
5,276,728,506
5,276,728,506
2 Depreciation Provisions for Year, Charged to
3
DepreciationExpenseExcludingAdjustments
(403) Depreciation Expense
328,977,598
328,977,598
4
DepreciationExpenseForAssetRetirementCosts
(403.1) Depreciation Expense for Asset Retirement Costs
7,744,824
7,744,824
5
ExpensesOfGasPlantLeasedToOthers
(413) Expense of Gas Plant Leased to Others
6
TransportationExpensesClearing
Transportation Expenses - Clearing
7
OtherClearingAccounts
Other Clearing Accounts
8
OtherAccounts
Other Clearing (Specify) (footnote details):
9.1
10
DepreciationProvision
TOTAL Deprec. Prov. for Year (Total of lines 3 thru 8)
321,232,774
321,232,774
11 Net Charges for Plant Retired:
12
BookCostOfRetiredPlant
Book Cost of Plant Retired
(a)
35,740,014
(e)
35,740,014
13
CostOfRemovalOfPlant
Cost of Removal
(b)
35,945,728
(f)
35,945,728
14
SalvageValueOfRetiredPlant
Salvage (Credit)
(c)
5,458,148
(g)
5,458,148
15
NetChargesForRetiredPlant
TOTAL Net Chrgs for Plant Ret. (Total of lines 12 thru 14)
(d)
66,227,594
(h)
66,227,594
16
Other Debit or Credit Items (Describe in footnote details)
17.1
(i)
9,542,673
(j)(k)
9,542,673
18
Book Cost of Asset Retirement Costs
2,827,765
2,827,765
19
Balance End of Year (Total of lines 1,10,15,16 and 18)
5,538,448,594
5,538,448,594
Section B. BALANCES AT END OF YEAR ACCORDING TO FUNCTIONAL CLASSIFICATIONS
21
AccumulatedDepreciationProductionsManufacturedGas
Productions-Manufactured Gas
22
AccumulatedDepreciationProductionAndGatheringNaturalGas
Production and Gathering-Natural Gas
132,512,544
132,512,544
23
AccumulatedDepreciationProductsExtractionNaturalGas
Products Extraction-Natural Gas
24
AccumulatedDepreciationUndergroundGasStorage
Underground Gas Storage
162,470,057
162,470,057
25
AccumulatedDepreciationOtherStorage
Other Storage Plant
51,390,798
51,390,798
26
AccumulatedDepreciationBaseLoadLngTerminalingAndProcessingPlant
Base Load LNG Terminaling and Processing Plant
27
AccumulatedDepreciationTransmission
Transmission
4,893,959,439
4,893,959,439
28
AccumulatedDepreciationDistribution
Distribution
29
AccumulatedDepreciationGeneral
General
298,115,756
298,115,756
30
AccumulatedProvisionForDepreciationOfGasUtilityPlant
TOTAL (Total of lines 21 thru 29)
5,538,448,594
5,538,448,594


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: BookCostOfRetiredPlant
Original value: -35740014
(b) Concept: CostOfRemovalOfPlant
Original value: -35945728
(c) Concept: SalvageValueOfRetiredPlant
Original value: -5458148
(d) Concept: NetChargesForRetiredPlant
Original value: -66227594
(e) Concept: BookCostOfRetiredPlant
Original value: -35740014
(f) Concept: CostOfRemovalOfPlant
Original value: -35945728
(g) Concept: SalvageValueOfRetiredPlant
Original value: -5458148
(h) Concept: NetChargesForRetiredPlant
Original value: -66227594
(i) Concept: OtherAdjustmentsToAccumulatedDepreciation
Original value: 9542673
(j) Concept: OtherAdjustmentsToAccumulatedDepreciation

 

$ 9,416,060

 

ARO SETTLEMENT OUT OF RETIREMENT WORK IN PROGRESS ACCOUNT

126,613

ALLOCATION OF FURNITURE AND EQUIPMENT DEPRECIATION TO CAPITAL

$ 9,542,673

(k) Concept: OtherAdjustmentsToAccumulatedDepreciation
Original value: 9542673

Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Gas Stored (Accounts 117.1, 117.2, 117.3, 117.4, 164.1, 164.2, and 164.3)
  1. If during the year adjustments were made to the stored gas inventory reported in columns (d), (f), (g), and (h) (such as to correct cumulative inaccuracies of gas measurements), explain in a footnote the reason for the adjustments, the Dth and dollar amount of adjustment, and account charged or credited.
  2. Report in (e) all encroachments during the year upon the volumes designated as base gas, column (b), and system balancing gas, column (c), and gas property recordable in the plant accounts.
  3. State in a footnote the basis of segregation of inventory between current and noncurrent portions. Also, state in a footnote the method used to report storage (i.e., fixed asset method or inventory method).
Line No.
Description
(a)
(Account 117.1)
(b)
(Account 117.2)
(c)
Noncurrent (Account 117.3)
(d)
(Account 117.4)
(e)
Current (Account 164.1)
(f)
LNG (Account 164.2)
(g)
LNG (Account 164.3)
(h)
Total
(i)
1
Balance at Beginning of Year
76,273,878
8,867,537
790,239
85,931,654
2
Gas Delivered to Storage
242,963
127,538,039
246,569
128,027,571
3
Gas Withdrawn from Storage
98,977,935
161,765
99,139,700
4
Other Debits and Credits
5
Balance at End of Year
76,516,841
37,427,641
875,043
114,819,525
6
Dth
(a)
80,439,190
(b)
10,739,924
(c)
2,435,377
(d)
93,614,491
7
Amount Per Dth
0.9512
3.4849
0.3593
1.2265


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: GasStoredBaseGasUnits

ALL BASE GAS IN ACCOUNT 117.1 IS CONSIDERED NON-CURRENT.

(b) Concept: SystemBalancingGasUnits

ALL GAS IN ACCOUNT 117.2 IS CONSIDERED CURRENT.

(c) Concept: LiquefiedNaturalGasStoredUnits

ALL GAS STORED IN THE LNG FACILITY (ACCOUNT 164.2) IS CONSIDERED CURRENT.

(d) Concept: StoredGasInventoryUnits

TRANSCO USES THE INVENTORY METHOD TO REPORT STORAGE.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Investments (Account 123, 124, and 136)
  1. Report below investments in Accounts 123, Investments in Associated Companies, 124, Other Investments, and 136, Temporary Cash Investments. List Account number in column (a).
  2. Provide a subheading for each account and list thereunder the information called for: (a) Investment in Securities-List and describe each security owned, giving name of issuer, date acquired and date of maturity. For bonds, also give principal amount, date of issue, maturity, and interest rate. For capital stock (including capital stock of respondent reacquired under a definite plan for resale pursuant to authorization by the Board of Directors, and included in Account 124, Other Investments) state number of shares, class, and series of stock. Minor investments may be grouped by classes. Investments included in Account 136, Temporary Cash Investments, also may be grouped by classes. (b) Investment Advances-Report separately for each person or company the amounts of loans or investment advances that are properly includable in Account 123. Include advances subject to current repayment in Account 145 and 146. With respect to each advance, show whether the advance is a note or open account.List each note, giving date of issuance, maturity date, and specifying whether note is a renewal. Designate any advances due from officers, directors, stockholders, or employees.
  3. Designate with an asterisk in column (b) any securities, notes or accounts that were pledged, and in a footnote state the name of pledges and purpose of the pledge.
  4. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and cite Commission, date of authorization, and case or docket number.
  5. Report in column (k) interest and dividend revenues from investments including such revenues from securities disposed of during the year.
  6. In column (l) report for each investment disposed of during the year the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including any dividend or interest adjustment includible in column (k).
Line No.
DescriptionOfInvestment
Description of Investment
(a)
IndicatorInvestmentsArePledged
*
(b)
DateOfAcquisitionForInvestments
Date Acquired
(c)
DateOfMaturityForInvestments
Date Matured
(d)
Row Specific Element
Book Cost at Beginning of Year (If book cost is different from cost to respondent, give cost to respondent in a footnote and explain difference)
(e)
Row Specific Element
Purchases or Additions During the Year
(f)
Row Specific Element
Sales or Other Dispositions During Year
(g)
InvestmentsInBondsPrincipal
Principal Amount
(h)
InvestmentsInCapitalStockNumberOfSharesForInvestments
No. of Shares at End of Year
(i)
Row Specific Element
Book Cost at End of Year (If book cost is different from cost to respondent, give cost to respondent in a footnote and explain difference)
(j)
Row Specific Element
Revenues for Year
(k)
Row Specific Element
Gain or Loss from Investment Disposed of
(l)
1
2
3
4
Total Investment in Associated Companies
1
2
3
4
Total Other Investments
1
2
3
4
Total Temporary Cash Investments
4
Total Investments


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Investments in Subsidiary Companies (Account 123.1)
  1. Report below investments in Account 123.1, Investments in Subsidiary Companies.
  2. Provide a subheading for each company and list thereunder the information called for below. Sub-total by company and give a total in columns (e), (f), (g) and (h). (a) Investment in Securities-List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal.
  3. Report separately the equity in undistributed subsidiary earnings since acquisition. The total in column (e) should equal the amount entered for Account 418.1.
  4. Designate in a footnote, any securities, notes, or accounts that were pledged, and state the name of pledgee and purpose of the pledge.
  5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number.
  6. Report in column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year.
  7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost), and the selling price thereof, not including interest adjustments includible in column (f).
  8. Report on Line 40, column (a) the total cost of Account 123.1.
Line No.
DescriptionOfInvestmentsInSubsidiaryCompanies
Description of Investment
(a)
DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Date Acquired
(b)
DateOfMaturityInvestmentsInSubsidiaryCompanies
Date of Maturity
(c)
InvestmentInSubsidiaryCompanies
Amount of Investment at Beginning of Year
(d)
EquityInEarningsOfSubsidiaryCompanies
Equity in Subsidiary earnings for Year
(e)
InterestAndDividendRevenueFromInvestments
Revenues for Year
(f)
InvestmentInSubsidiaryCompanies
Amount of Investment at End of Year
(g)
InvestmentGainLossOnDisplosal
Gain or Loss from Investment Disposed of
(h)
1
Pine Needle Operating Company, LLC
09/15/2009
1,000
1,000
2
TOTAL PINE NEEDLE OPERATING COMPANY, LLC
1,000
1,000
3
Cardinal Operating Company, LLC
09/14/2009
1,000
1,000
4
TOTAL CARDINAL OPERATING COMPANY, LLC
1,000
1,000
5
Transcarolina LNG Company, LLC
09/15/2009
22,520,288
22,520,288
6
Undistributed Earnings
8,602,670
379,901
(i)
8,982,571
7
Return of Capital
8
Distributions
(b)
28,500,000
(e)
150,000
(j)
28,650,000
9
Derivative
55,456
(f)
7,232
48,224
10
TOTAL TRANSCAROLINA LNG COMPANY, LLC
2,678,414
379,901
157,232
2,901,083
11
Transcardinal Company, LLC
09/14/2009
24,528,750
24,528,750
12
Undistributed Earnings
13,886,771
281,484
(k)
14,168,255
13
Return of Capital
14
Distributions
(d)
28,900,000
(g)
2,850,000
(l)
31,750,000
15
Derivative
195,544
(h)
148,022
343,566
16
TOTAL TRANSCARDINAL COMPANY, LLC
9,711,065
281,484
2,701,978
7,290,571
40
TOTAL Cost of Account 123.1 $
9,695,825
Total
12,391,479
661,385
2,859,210
10,193,654


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: InvestmentInSubsidiaryCompanies

 

DUE TO THE ADOPTION OF ASU 2016-15, RETURN OF CAPITAL BEGINNING BALANCE AMOUNTS WERE MOVED TO DISTRIBUTIONS. SEE NOTES TO FINANCIAL STATEMENTS.

(b) Concept: InvestmentInSubsidiaryCompanies

 

SEE FOOTNOTE SCHEDULE PAGE 224, LINE NO.:7 COLUMN: d

(c) Concept: InvestmentInSubsidiaryCompanies

 

SEE FOOTNOTE SCHEDULE PAGE 224, LINE NO.:7 COLUMN: d

(d) Concept: InvestmentInSubsidiaryCompanies

 

SEE FOOTNOTE SCHEDULE PAGE 224, LINE NO.:7 COLUMN: d

(e) Concept: InterestAndDividendRevenueFromInvestments

 

DISTRIBUTIONS FROM TRANSCAROLINA LNG COMPANY, LLC.

(f) Concept: InterestAndDividendRevenueFromInvestments

 

EQUITY IN OTHER COMPREHENSIVE INCOME/LOSS (OCI) OF TRANSCAROLINA WHICH RESULTS FROM TRANSCAROLINA’S EQUITY IN THE OCI OF PINE NEEDLE DUE TO PINE NEEDLE’S CASH FLOW HEDGE DERIVATIVE.

(g) Concept: InterestAndDividendRevenueFromInvestments

 

DISTRIBUTIONS FROM TRANSCARDINAL COMPANY, LLC.

(h) Concept: InterestAndDividendRevenueFromInvestments

 

EQUITY IN OTHER COMPREHENSIVE INCOME/LOSS (OCI) OF TRANSCARDINAL WHICH RESULTS FROM TRANSCARDINAL’S EQUITY IN THE OCI OF CARDINAL DUE TO CARDINAL’S CASH FLOW HEDGE DERIVATIVE.

(i) Concept: InvestmentInSubsidiaryCompanies

 

EQUITY IN UNDISTRIBUTED EARNINGS SINCE ACQUISITION:

 

 

TRANSCAROLINA LNG COMPANY, LLC

$

8,982,571

DISTRIBUTION FROM TRANSCAROLINA LNG COMPANY, LLC

 

(28,650,000)

TRANSCARDINAL COMPANY, LLC

 

14,168,255

DISTRIBUTION FROM TRANSCARDINAL COMPANY, LLC

 

(31,750,000)

 

$

(37,249,174)

 

NOTE 1: DIFFERENCE BETWEEN THIS AND ACCOUNT 216.1 (UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS) IS THE EQUITY IN WGP ENTERPRISES THAT RESULTED FROM THE NONCASH DIVIDEND OF STOCK OF WGP ENTERPRISES TO WGP IN DECEMBER 2001, AND THE EQUITY IN TRANSCUMBERLAND PIPELINE COMPANY, TRANSCO INDEPENDENCE PIPELINE COMPANY, TGPL ENTERPRISES, LLC, TRANSCO CROSS BAY COMPANY AT THE TIME OF DISSOLUTION AND THE EQUITY IN MARSH RESOURCES, LLC, TRANSCAROLINA LNG COMPANY, LLC AND TRANSCARDINAL COMPANY, LLC THAT RESULTED FROM THE NONCASH DIVIDEND OF STOCK OF MARSH RESOURCES, LLC, TRANSCAROLINA LNG COMPANY, LLC AND TRANSCARDINAL COMPANY, LLC TO WGP IN DECEMBER 2008. ALSO INCLUDED IN THE DIFFERENCE ARE SPECIAL DISTRIBUTIONS FROM TRANSCAROLINA LNG COMPANY, LLC AND TRANSCARDINAL COMPANY, LLC TO TRANSCO.

(j) Concept: InvestmentInSubsidiaryCompanies

 

SEE FOOTNOTE SCHEDULE PAGE 224, LINE NO.:6 COLUMN: g

(k) Concept: InvestmentInSubsidiaryCompanies

 

SEE FOOTNOTE SCHEDULE PAGE 224, LINE NO.:6 COLUMN: g

(l) Concept: InvestmentInSubsidiaryCompanies

 

SEE FOOTNOTE SCHEDULE PAGE 224, LINE NO.:6 COLUMN: g


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Prepayments (Acct 165), Extraordinary Property Losses (Acct 182.1), Unrecovered Plant and Regulatory Study Costs (Acct 182.2)

PREPAYMENTS (ACCOUNT 165)
  1. Report below the particulars (details) on each prepayment.
Line No.
Nature of Payment
(a)
Balance at End of Year (in dollars)
(b)
1
PrepaidInsurance
Prepaid Insurance
7,473,214
2
PrepaidRents
Prepaid Rents
1,139,949
3
PrepaidTaxes
Prepaid Taxes
4
PrepaidInterest
Prepaid Interest
5
MiscellaneousPrepayments
Miscellaneous Prepayments
6
Prepayments
TOTAL
8,613,163


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Prepayments (Acct 165), Extraordinary Property Losses (Acct 182.1), Unrecovered Plant and Regulatory Study Costs (Acct 182.2) (continued)
EXTRAORDINARY PROPERTY LOSSES (ACCOUNT 182.1)
  1. Include the date of loss, the date of Commission authorization to use Account 182.1 and period of amortization (mo, yr, to mo, yr)].
  2. Add rows as necessary to report all data. Number rows in sequence beginning with the next row number after the last row number used for extraordinary property losses.
Line No.
DescriptionOfExtraordinaryPropertyLoss
Description of Extraordinary Loss [include the date of loss, the date of Commission authorization to use Account 182.1 and period of amortization (mo, yr, to mo, yr)] Add rows as necessary to report all data.
(a)
ExtraordinaryPropertyLosses
Balance at Beginning of Year
(b)
RegulatoryDebits
Total Amount of Loss
(c)
ExtraordinaryPropertyLossesRecognized
Losses Recognized During Year
(d)
ExtraordinaryPropertyLossesWrittenOffAccountCharged
Written off During Year Account Charged
(e)
ExtraordinaryPropertyLossesWrittenOff
Written off During Year Amount
(f)
ExtraordinaryPropertyLosses
Balance at End of Year
(g)
7
8
9
10
11
12
13
14
15
TOTAL


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Prepayments (Acct 165), Extraordinary Property Losses (Acct 182.1), Unrecovered Plant and Regulatory Study Costs (Acct 182.2) (continued)
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (ACCOUNT 182.2)
  1. Include in the description of costs, the date of Commission authorization to use Account 182.2 and period of amortization (mo, yr, to mo, yr).
  2. Add rows as necessary to report all data. Number rows in sequence beginning with the next row number after the last row number used for extraordinary property losses.
Line No.
DescriptionOfUnrecoveredPlantAndRegulatoryStudyCosts
Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of Commission authorization to use Account 182.2 and period of amortization (mo, yr, to mo, yr)] Add rows as necessary to report all data. Number rows in sequence beginning with the next row number after the last row number used for extraordinary property losses.
(a)
UnrecoveredPlantAndRegulatoryStudyCosts
Balance at Beginning of Year
(b)
UnrecoveredPlantAndRegulatoryStudyCostsNotYetRecognized
Total Amount of Charges
(c)
UnrecoveredPlantAndRegulatoryStudyCostsRecognized
Costs Recognized During Year
(d)
UnrecoveredPlantAndRegulatoryStudyCostsWrittenOffAccountCharged
Written off During Year Account Charged
(e)
UnrecoveredPlantAndRegulatoryStudyCostsWrittenOff
Written off During Year Amount
(f)
UnrecoveredPlantAndRegulatoryStudyCosts
Balance at End of Year
(g)
16
17
18
19
20
21
22
23
24
25
26
TOTAL


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Other Regulatory Assets (Account 182.3)
  1. Report below the details called for concerning other regulatory assets which are created through the ratemaking actions of regulatory agencies (and not includable in other accounts).
  2. For regulatory assets being amortized, show period of amortization in column (b).
  3. Minor items (5% of the Balance at End of Year for Account 182.3 or amounts less than $250,000, whichever is less) may be grouped by classes.
  4. Report separately any "Deferred Regulatory Commission Expenses" that are also reported on pages 350-351, Regulatory Commission Expenses.
  5. Provide in column (c), for each line item, the regulatory citation where authorization for the regulatory asset has been granted (e.g. Commission Order, state commission order, court decision).
Line No.
DescriptionAndPurposeOfOtherRegulatoryAssets
Description and Purpose of Other Regulatory Assets
(a)
AmortizationPeriodOtherRegulatoryAssets
Amortization Period
(b)
CitationAuthorizationForOtherRegulatoryAssets
Regulatory Citation
(c)
OtherRegulatoryAssets
Balance at Beginning Current Quarter/Year
(d)
IncreaseDecreaseInOtherRegulatoryAssets
Debits
(e)
OtherRegulatoryAssetsWrittenOffAccountCharged
Written off During Quarter/Year Account Charged
(f)
OtherRegulatoryAssetsWrittenOffRecovered
Written off During Period Amount Recovered
(g)
OtherRegulatoryAssetsWrittenOffDeemedUnrecoverable
Written off During Period Amount Deemed Unrecoverable
(h)
OtherRegulatoryAssets
Balance at End of Current Quarter/Year
(i)
1
Environmental Costs
2,238,377
2,238,377
2
(a)
Cash-Out Deferral
42,507,288
12,358,392
54,865,680
3
Fuel Tracker - Transportation, Storage Deferral,
4
(b)
and Carrying Costs
59,550,254
16,769,199
16,362,747
59,956,706
5
(c)
LNG Fuel Tracker and Carrying Costs
1,854,699
373,570
964,314
1,263,955
6
Deferred Tax Related to AFUDC
7
(d)
(03/01/2013 - 07/15/2050)
111,178,310
50,186,405
4,579,798
156,784,917
8
Deferred Tax Related to an Increase
9
in State Tax Rate Including Current
10
(e)
(03/01/2007 - 06/30/2021)
3,757,906
1,077,780
2,680,126
11
Eminence Abandonment Costs
12
(f)
(03/01/2013 - 03/01/2028)
49,465,532
3,976,610
45,488,922
13
(g)
Asset Retirement Obligation - Tracker
167,479,015
31,775,669
28,615,028
170,639,656
14
Asset Retirement Obligation - ARO Trust
15
(h)
Withdrawal Deferral
1,196,164
60,512
3,946
1,252,730
16
(i)
Deferred Gas Costs
6,000,000
12,103,767
14,072,012
4,031,755
17
(j)
Deferred Tax Liability - State Rate Change 2018
85,189,830
85,189,830
40
TOTAL
445,227,545
208,817,344
69,652,235
2,238,377
582,154,277


FOOTNOTE DATA

(a) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 15

(b) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

FERC GAS TARIFF SECTION 38.5

(c) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

FERC GAS TARIFF SECTION 38.5

(d) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

FERC ACCOUNTING GUIDANCE AI93-5-000, ACCOUNTING FOR INCOME TAXES

(e) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

SOUTH GEORGIA NATURAL GAS CO., FERC DOCKET RP77-32 (1978)

(f) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

DOCKET NO. RP12-993

AMORTIZATION PERIOD OF 15 YEARS, THROUGH MARCH 1, 2028

(g) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

RP12-993 RATE CASE SETTLEMENT, DISBURSEMENTS FROM THE TRUST WILL BE LIMITED BASED ON ESTABLISHED CRITERIA IN SETTLEMENT, ANY SPENDING IN EXCESS OF ESTABLISHED AMOUNTS ARE DEFERRED

(h) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

RP12-993 RATE CASE SETTLEMENT, DISBURSEMENTS FROM THE TRUST WILL BE LIMITED BASED ON ESTABLISHED CRITERIA IN SETTLEMENT, ANY SPENDING IN EXCESS OF ESTABLISHED AMOUNTS ARE DEFERRED

(i) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 15

(j) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

RELATES TO THE ESTABLISHMENT OF A REGULATORY ASSET DUE TO THE WPZ MERGER IN AUGUST 2018 WHICH RESULTED IN AN INCREASED EFFECTIVE STATE INCOME TAX RATE


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Miscellaneous Deferred Debits (Account 186)
  1. Report below the details called for concerning miscellaneous deferred debits
  2. For any deferred debit being amortized, show period of amortization in column (a).
  3. Minor items (less than $250,000) may be grouped by classes.
Line No.
DescriptionOfMiscellaneousDeferredDebits
Description of Miscellaneous Deferred Debits
(a)
MiscellaneousDeferredDebitsExcludingMiscellaneousWorkInProgress
Balance at Beginning of Year
(b)
IncreaseInMiscellaneousDeferredExpense
Debits
(c)
DecreaseInMiscellaneousDeferredExpenseAccountCharged
Credits Account Charged
(d)
DecreaseInMiscellaneousDeferredExpense
Credits Amount
(e)
MiscellaneousDeferredDebitsExcludingMiscellaneousWorkInProgress
Balance at End of Year
(f)
1
Deferred Regulatory Commission Expenses
3,281,866
4,988,478
4,528,989
3,741,355
2
Suspense Projects
17,719,021
1,789,882
15,929,139
3
338,824
338,824
4
1,805
1,805
5
5,781,125
5,781,125
6
3,798,921
3,798,921
7
19
19
8
151
151
9
634
634
10
32
32
11
76
76
12
Other
30,531
20,621
51,152
39
Miscellaneous Work in Progress
40
TOTAL
3,312,397
22,728,120
16,240,458
9,800,059


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
Accumulated Deferred Income Taxes (Account 190)
  1. Report the information called for below concerning the respondent’s accounting for deferred income taxes.
  2. At Other (Specify), include deferrals relating to other income and deductions.
  3. Provide in a footnote a summary of the type and amount of deferred income taxes reported in the beginning-of-year and end-of-year balances for deferred income taxes that the respondent estimates could be included in the development of jurisdictional recourse rates.
Line No.
Account Subdivisions
(a)
Balance at Beginning of Year
(b)
Changes During Year Amounts Debited to Account 410.1
(c)
Changes During Year, Amounts Credited to Account 411.1
(d)
Changes During Year Amounts Debited to Account 410.2
(e)
Changes During Year Amounts Credited to Account 411.2
(f)
Adjustments Debits Account No.
(g)
Adjustments Debits Amount
(h)
Adjustments Credits Account No.
(i)
Adjustments Credits Amount
(j)
Balance at End of Year
(k)
1
Account 190
2
Electric
3
Gas
427,562,810
44,207,223
146,104,633
53,047,633
16,632,223
493,044,810
4
Other (Define)
5
Total (Total of lines 2 thru 4)
427,562,810
44,207,223
146,104,633
53,047,633
16,632,223
493,044,810
6
Other (Specify)
7
TOTAL Account 190 (Total of lines 5 thru 6)
427,562,810
44,207,223
146,104,633
53,047,633
16,632,223
(a)
493,044,810
8
Classification of TOTAL
9
Federal Income Tax
337,557,365
15,296,000
99,695,633
53,047,633
368,909,365
10
State Income Tax
90,005,445
28,911,223
46,409,000
16,632,223
124,135,445
11
Local Income Tax


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxes

 

 

DEF

 

 

 

 

 

TAX

 

 

 

 

 

ACCT

12/31/2018

12/31/2018

 

12/31/2018

 

& CTD

TOTAL

CTD’S

NOT IN

ADJUSTED

 

TYPE

CTD’S

@0.2621

RATE BASE

ADIT

 

 

 

 

 

 

ACCR AUDIT SERVICES A/P

190 NC

$ 282,000

$ 73,923

$ (73,923)

$ -

RESERVE FOR BAD DEBTS

190 NC

7,941

2,082

(2,082)

-

CONTINGENCIES-CURR – DEFAULT

190 NC

1,795,400

470,646

(470,646)

-

REG LIAB-NCURR-RATE BASE RSG 2017

190 NC

803,981,012

210,755,582

 

210,755,582

CONTINGENCIES-SELF INSURANCE LIAB

190 NC

306,197

80,266

(80,266)

-

ENVIRONMENTAL LIABILITY-DEFAULT

190 NC

1,468,000

384,822

(384,822)

-

ENVIRONMENTAL LIABILITY-DEFAULT

190 NC

1,992,000

522,183

(522,183)

-

RESERVE-INVENTORY

190 NC

45,305

11,876

(11,876)

-

OTH LIAB-MISC RESERVE

190 NC

5,214,981

1,367,055

(1,367,055)

-

OTH LIAB-ARO

190 NC

45,713,817

11,983,420

(11,983,420)

-

DEFERRED REV-NCURR TRANS PREPAY

190 NC

9,905,667

2,596,672

(2,596,672)

-

OTHER DEFERRED-ARO

190 NC

326,533,603

85,596,363

(85,596,363)

-

OTH LIAB-RECYCLABLE MATERIAL FUND

190 NC

484

127

(127)

-

OTH LIAB-NC-ADDITIONAL MIN LIAB

190 NC

1,290,182

338,208

(338,208)

-

INT EXP -263A – PP&E COST ADJ

190 NC

311,996,115

81,786,662

-

81,786,662

PP&E COST ADJ-CIACS

190 NC

370,317,093

97,074,923

(97,074,923)

-     

 

 

$ 1,880,849,797

$ 493,044,810

$ (200,502,566)

$ 292,542,244


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Capital Stock (Accounts 201 and 204)
  1. Report below the details called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock.
  2. Entries in column (c) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
  3. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued.
  4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative.
  5. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year.
  6. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purpose of pledge.
Line No.
Class and Series of Stock and Name of Stock Exchange
(a)
Number of Shares Authorized by Charter
(b)
Par or Stated Value per Share
(c)
Call Price at End of Year
(d)
Outstanding per Bal. Sheet (total amt outstanding without reduction for amts held by respondent) Shares
(e)
Outstanding per Bal. Sheet Amount
(f)
Held by Respondent As Reacquired Stock (Acct 217) Shares
(g)
Held by Respondent As Reacquired Stock (Acct 217) Cost
(h)
Held by Respondent In Sinking and Other Funds Shares
(i)
Held by Respondent In Sinking and Other Funds Amount
(j)
1
Common Stock (Account 201)
2
3
4
5
Total
6
Preferred Stock (Account 204)
7
8
9
10
Total
11
Total


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Capital Stock: Subscribed, Liability for Conversion, Premium on, and Installments Recieved on (Accts 202, 203, 205, 206, 207, and 212)
  1. Show for each of the above accounts the amounts applying to each class and series of capital stock.
  2. For Account 202, Common Stock Subscribed, and Account 205, Preferred Stock Subscribed, show the subscription price and the balance due on each class at the end of year.
  3. Describe in a footnote the agreement and transactions under which a conversion liability existed under Account 203, Common tock Liability for Conversion, or Account 206, Preferred Stock Liability for Conversion, at the end of year.
  4. For Premium on Account 207, Capital Stock, designate with an asterisk in column (c), any amounts representing the excess of consideration received over stated values of stocks without par value.
Line No.
Name of Account and Description of Item
(a)
*
(b)
Number of Shares
(c)
Amount
(d)
1
Common Stock, Subscribed (Account 202)
2
3
4
5
Total
6
Common Stock, Converted to Liability (Account 203)
7
8
9
10
Total
11
Preferred Stock, Subscribed (Account 205)
12
13
14
15
Total
16
Preferred Stock Liability for Conversion (Account 206)
17
18
19
20
Total
21
Premium on Capital Stock (Account 207)
22
23
24
25
Total
26
Installments on Capital Stock (Account 212)
27
28
29
30
Total
40
Total


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
Other Paid-In Capital (Accounts 208-211)
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change.
  1. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation.
  2. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related.
  3. Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) - Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
  4. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.
Item
(a)
Amount
(b)
1
DonationsReceivedFromStockholdersAbstract
Donations Received from Stockholders (Account 208)
2
DonationsReceivedFromStockholders
Beginning Balance Amount
3
IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders
Increases (Decreases) from Sales of Donations Received from Stockholders
4
DonationsReceivedFromStockholders
Ending Balance Amount
5
ReductionInParOrStatedValueOfCapitalStockAbstract
Reduction in Par or Stated Value of Capital Stock (Account 209)
6
ReductionInParOrStatedValueOfCapitalStock
Beginning Balance Amount
7
IncreasesDecreasesDueToReductionsInParOrStatedValueOfCapitalStock
Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8
ReductionInParOrStatedValueOfCapitalStock
Ending Balance Amount
9
GainOrResaleOrCancellationOfReacquiredCapitalStockAbstract
Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10
GainOnResaleOrCancellationOfReacquiredCapitalStock
Beginning Balance Amount
11
IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock
Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12
GainOnResaleOrCancellationOfReacquiredCapitalStock
Ending Balance Amount
13
MiscellaneousPaidInCapitalAbstract
Miscellaneous Paid-In Capital (Account 211)
14
MiscellaneousPaidInCapital
Beginning Balance Amount
15
IncreasesDecreasesDueToMiscellaneousPaidInCapital
Increases (Decreases) Due to Miscellaneous Paid-In Capital
16
MiscellaneousPaidInCapital
Ending Balance Amount
17
OtherPaidInCapitalAbstract
Other Paid in Capital
18
OtherPaidInCapitalDetail
Beginning Balance Amount
19.1
IncreasesDecreasesInOtherPaidInCapital
Account 210 - Gain on Resale of Cancellation of Reaquired Capital Stock
8,464,194
19.2
IncreasesDecreasesInOtherPaidInCapital
Account 211 - Federal Income Tax Savings Resulting From Employee Benefit Program
125,779
19.3
IncreasesDecreasesInOtherPaidInCapital
Transtock Contribution
45,166,645
19.4
IncreasesDecreasesInOtherPaidInCapital
Capital Contribution
(a)
3,064,799,414
19.5
IncreasesDecreasesInOtherPaidInCapital
Return of Capital to Parent
697,916
20
OtherPaidInCapitalDetail
Ending Balance Amount
40
OtherPaidInCapital
Total
3,117,858,116


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: IncreasesDecreasesInOtherPaidInCapital

 

TRANSCONTINENTAL GAS PIPE LINE COMPANY RECEIVED QUARTERLY EQUITY CONTRIBUTIONS FROM WILLIAMS PARTNERS OPERATING LLC IN THE FOLLOWING AMOUNTS: $340 MILLION IN MARCH 2018.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
DISCOUNT ON CAPITAL STOCK (ACCOUNT 213)
  1. Report the balance at end of year of discount on capital stock for each class and series of capital stock. Use as many rows as necessary to report all data.
  2. If any change occurred during the year in the balance with respect to any class or series of stock, attach a statement giving details of the change. State the reason for any charge-off during the year and specify the account charged.
Line No.
NameOfClassAndSeriesOfStock
Class and Series of Stock
(a)
DiscountOnCapitalStock
Balance at End of Year
(b)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Total
Capital Stock Expense (Account 214)
  1. Report the balance at end of year of capital stock expenses for each class and series of capital stock. Use as many rows as necessary to report all data. Number the rows in sequence starting from the last row number used for Discount on Capital Stock above.
  2. If any change occurred during the year in the balance with respect to any class or series of stock, attach a statement giving details of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line No.
NameOfClassAndSeriesOfStock
Class and Series of Stock
(a)
CapitalStockExpense
Balance at End of Year
(b)
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Total


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Securities Issued or Assumed and Securities Refunded or Retired During the Year
  1. Furnish a supplemental statement briefly describing security financing and refinancing transactions during the year and the accounting for the securities, discounts, premiums, expenses, and related gains or losses. Identify as to Commission authorization numbers and dates.
  2. Provide details showing the full accounting for the total principal amount, par value, or stated value of each class and series of security issued, assumed, retired, or refunded and the accounting for premiums, discounts, expenses, and gains or losses relating to the securities. Set forth the facts of the accounting clearly with regard to redemption premiums, unamortized discounts, expenses, and gain or losses relating to securities retired or refunded, including the accounting for such amounts carried in the respondent's accounts at the date of the refunding or refinancing transactions with respect to securities previously refunded or retired.
  3. Include in the identification of each class and series of security, as appropriate, the interest or dividend rate, nominal date of issuance, maturity date, aggregate principal amount, par value or stated value, and number of shares. Give also the issuance of redemption price and name of the principal underwriting firm through which the security transactions were consummated.
  4. Where the accounting for amounts relating to securities refunded or retired is other than that specified in General Instruction 17 of the Uniform System of Accounts, cite the Commission authorization for the different accounting and state the accounting method.
  5. For securities assumed, give the name of the company for which the liability on the securities was assumed as well as details of the transactions whereby the respondent undertook to pay obligations of another company. If any unamortized discount, premiums, expenses, and gains or losses were taken over onto the respondent's books, furnish details of these amounts with amounts relating to refunded securities clearly earmarked.

 

Securites Issued During Year

Principal Amount of Notes Issued $400,000,000 (1)

Interest Rate 4.00%

Date of Issuance March 15, 2018

Maturity Date March 15, 2028

Issue Expense Incurred Through 12/31/2018 $3,519,135 (2)

 

Principal Amount of Notes Issued $600,000,000 (1)

Interest Rate 4.60%

Date of Issuance March 15, 2018

Maturity Date March 15, 2048

Issue Expense Incurred Through 12/31/2018 $6,628,702 (2)

 

 

 

Securities Retired During Year

Principal Amount of Notes Issued $250,000,000 (3)

Interest Rate 6.05%

Date of Issuance May 22, 2008

Maturity Date June 15, 2018

Issue Expense Incurred Through 06/15/2018 $2,100,296 (4)

 

Securites Issued and Retired During Year

On March 15, 2018, we issued $400 million of 4.0 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private debt placement. We used the net proceeds to repay indebtedness, including our $250 million of 6.05 percent senior unsecured notes due 2018 upon their maturity on June 15, 2018, and for general corporate purposes, including the funding of capital expenditures. The notes were issued under an Indenture, dated as of March 15, 2018 between us and The Bank of New York Mellon Trust Company, N.A., as trustee. As part of the issuance, we entered into a registration rights agreement with the initial purchasers of the notes. Under the terms of the agreement, we were obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act within 365 days after closing and to use commercially reasonable efforts to complete the exchange offer. We filed a registration statement, which was subsequently declared effective by the SEC, and consummated the exchange offer in the third quarter of 2018.

 

 

Notes:

1. Credited to Account 224

2. Charged to Account 181

3. Charged to Account 224

4. Credited to Account 181 through amortization








Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Long-Term Debt (Accounts 221, 222, 223, and 224)
  1. Report by Balance Sheet Account the details concerning long-term debt included in Account 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt.
  2. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
  3. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received.
  4. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued.
  5. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a)principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates.
  6. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge.
  7. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote.
  8. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (g). Explain in a footnote any difference between the total of column (g) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
  9. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.
ClassOfSeriesOfObligationAndNameOfStockExchange
Class and Series of Obligation and Name of Stock Exchange
(a)
NominalDateOfIssue
Nominal Date of Issue
(b)
DateOfMaturity
Date of Maturity
(c)
Outstanding (Total amount outstanding without reduction for amts held by respondent)
(d)
InterestRate
Interest for Year Rate (in %)
(e)
Interest for Year Amount
(f)
Held by Respondent Reacquired Bonds (Acct 222)
(g)
Held by Respondent Sinking and Other Funds
(h)
RedemptionPrice
Redemption Price per $100 at End of Year
(i)
1
Bonds (Account 221)
2
3
4
5
Subtotal
207,500,000
6
Reacquired Bonds (Account 222)
7
8
9
10
Subtotal
11
Advances from Associated Companies (Account 223)
12
13
14
15
Subtotal
16
Other Long Term Debt (Account 224)
17
18
19
20
Subtotal
2,775,000,000
Long Term Debt (Historical Data)
1
Account 221 - Debenture 7.08% Due 2026
07/15/1996
07/15/2026
7,500,000
7.08
531,000
2
Account 221 - Debenture 7.25% Due 2026
12/02/1996
12/01/2026
200,000,000
7.25
14,500,000
3
Total Account 221
207,500,000
15,031,000
4
Account 224 - Notes 6.05% Due 2018
05/22/2008
06/15/2018
6.05
6,890,278
5
Account 224 - Notes 5.4% Due 2041
08/12/2011
08/15/2041
375,000,000
5.4
20,250,000
6
Account 224 - Notes 4.45% Due 2042
07/13/2012
08/01/2042
400,000,000
4.45
17,800,000
7
Account 224 - Notes 7.85% Due 2026
01/22/2016
02/01/2026
1,000,000,000
7.85
78,500,000
8
Account 224 - Notes 4.0% Due 2028
03/15/2018
03/15/2028
400,000,000
4
12,711,111
9
Account 224 - Notes 4.6 % Due 2048
03/15/2018
03/15/2048
600,000,000
4.6
21,926,667
10
Total Account 224
2,775,000,000
158,078,056
40 TOTAL
2,982,500,000
173,109,056


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Unamortized Debt Expense, Premium and Discount on Long-Term Debt (Accounts 181, 225, 226)
  1. Report under separate subheadings for Unamortized Debt Expense, Unamortized Premium on Long-Term Debt and Unamortized Discount on Long-Term Debt, details of expense, premium or discount applicable to each class and series of long-term debt.
  2. Show premium amounts by enclosing the figures in parentheses.
  3. In column (d) show the principal amount of bonds or other long-term debt originally issued.
  4. In column (e) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
  5. Furnish in a footnote details regarding the treatment of unamortized debt expense, premium or discount associated with issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as specified by the Uniform System of Accounts.
  6. Identify separately undisposed amounts applicable to issues which were redeemed in prior years.
  7. Explain any debits and credits other than amortization debited to Account 428, Amortization of Debt Discount and Expense, or credited to Account 429, Amortization of Premium on Debt-Credit.
Line No.
DesignationOfLongTermDebt
Designation of Long-Term Debt
(a)
LongTermDebtPrincipalAmountIssued
Principal Amount of Debt Issued
(b)
Total expense - Premium; Discount; or Debt Issuance Costs
(c)
AmortizationPeriodStartDate
Amortization Period Date From
(d)
AmortizationPeriodEndDate
Amortization Period Date To
(e)
Balance at Beginning of Year
(f)
Debits During Year
(g)
AmortizationOfPremiumOnLongTermDebt
Credits During Year
(h)
Balance at End of Year
(i)
1
Unamortized Debt Expense (Account 181)
2
3
4
5
Premium on Long-Term Debt (Account 225)
6
7
8
9
Discount on Long-Term Debt (Account 226)
10
11
12
Historical Data
1
Account 181 - Unamortized Debt Expense
2
Debenture 7.25% Due 2026
200,000,000
1,881,003
12/02/1996
12/01/2026
558,465
62,631
495,834
3
Notes 6.05% Due 2018
250,000,000
2,100,296
05/22/2008
06/15/2018
96,045
96,045
4
Notes 5.4% Due 2041
375,000,000
4,022,860
08/12/2011
08/15/2041
3,611,213
76,983
3,534,230
5
Notes 4.45% Due 2042
400,000,000
4,286,569
07/13/2012
08/01/2042
3,859,341
87,728
3,771,613
6
Notes 7.85% Due 2026
1,000,000,000
8,394,194
01/22/2016
02/01/2026
7,252,180
665,793
6,586,387
7
Notes 4.0% Due 2028
400,000,000
3,519,135
03/15/2018
03/15/2028
3,519,135
216,304
3,302,831
8
Notes 4.6% Due 2048
600,000,000
6,628,702
03/15/2018
03/15/2048
6,628,702
78,115
6,550,587
9
TOTAL ACCOUNT 181
30,832,759
15,377,244
10,147,837
1,283,599
24,241,482
10
Account 226 - Unamortized Discount on Long-Term Debt
11
Debenture 7.25% Due 2026
200,000,000
340,000
12/02/1996
12/01/2026
182,353
15,093
167,260
12
Notes 6.05% Due 2018
250,000,000
667,500
05/22/2008
06/15/2018
39,824
39,824
13
Notes 5.4% Due 2041
375,000,000
2,482,500
08/12/2011
08/15/2041
2,231,888
47,761
2,184,127
14
Notes 4.45% Due 2042
400,000,000
1,196,000
07/13/2012
08/01/2042
1,079,051
24,690
1,054,361
15
Notes 7.85% Due 2026
1,000,000,000
1,750,000
01/22/2016
02/01/2026
1,509,549
139,114
1,370,435
16
Notes 4.0% Due 2028
400,000,000
2,216,000
03/15/2018
03/15/2028
2,216,000
145,107
2,070,893
17
Notes 4.6% Due 2048
600,000,000
4,344,000
03/15/2018
03/15/2048
4,344,000
53,994
4,290,006
18
TOTAL ACCOUNT 226
12,996,000
5,042,665
6,560,000
465,583
11,137,082


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Unamortized Loss and Gain on Reacquired Debt (Accounts 189, 257)
  1. Report under separate subheadings for Unamortized Loss and Unamortized Gain on Reacquired Debt, details of gain and loss, including maturity date, on reacquisition applicable to each class and series of long-term debt. If gain or loss resulted from a refunding transaction, include also the maturity date of the new issue.
  2. In column (d) show the principal amount of bonds or other long-term debt reacquired.
  3. In column (e) show the net gain or net loss realized on each debt reacquisition as computed in accordance with General Instruction 17 of the Uniform Systems of Accounts.
  4. Show loss amounts by enclosing the figures in parentheses.
  5. Explain in a footnote any debits and credits other than amortization debited to Account 428.1, Amortization of Loss on Reacquired Debt, or credited to Account 429.1, Amortization of Gain on Reacquired Debt-Credit.
Line No.
DesignationOfLongTermDebt
Designation of Long-Term Debt
(a)
DateOfMaturity
Date of Maturity
(b)
DateOfDebtReacquired
Date Reacquired
(c)
LongTermDebtReacquiredPrincipalAmount
Principal of Debt Reacquired
(d)
Net Gain or Loss
(e)
Balance at Beginning of Year
(f)
Balance at End of Year
(g)
1 Unamortized Loss (Account 189)
2
3
4
5
Unamortized Gain (Account 257)
6
7
8
Historical Data
1
Account 181 - Unamortized Debt Expense
2
Debenture 7.25% Due 2026
3
Notes 6.05% Due 2018
4
Notes 5.4% Due 2041
5
Notes 4.45% Due 2042
6
Notes 7.85% Due 2026
7
Notes 4.0% Due 2028
8
Notes 4.6% Due 2048
9
TOTAL ACCOUNT 181
10
Account 226 - Unamortized Discount on Long-Term Debt
11
Debenture 7.25% Due 2026
12
Notes 6.05% Due 2018
13
Notes 5.4% Due 2041
14
Notes 4.45% Due 2042
15
Notes 7.85% Due 2026
16
Notes 4.0% Due 2028
17
Notes 4.6% Due 2048
18
TOTAL ACCOUNT 226


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Reconciliation of Reported Net Income with Taxable Income for Feder Income Taxes
  1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal Income Tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
  2. If the utility is a member of a group that files consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be filed, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group members, tax assigned to each group member, and basis of allocation, assignments, or sharing of the consolidated tax among the group members.
Line No.
Details
(a)
Amount
(b)
1
Net Income for the Year (Page 114)
583,024,561
2
Reconciling Items for the Year
3
4
Taxable Income Not Reported on Books
5
Contributions in Aid of Construction
47,351,000
8
47,351,000
9
Deductions Recorded on Books Not Deducted for Return
10
Book Depreciation
326,486,000
11
Federal Current and Deferred Income Tax
153,361,251
12
Other
(a)
121,800,000
13
601,647,251
14
Income Recorded on Books Not Included in Return
15
Allowance for Funds Used During Construction
(b)
87,111,000
16
Equity in Earnings-Subsidiaries
(c)
661,000
18
(d)
87,772,000
19
Deductions on Return Not Charged Against Book Income
20
Tax Depreciation
(e)
490,763,820
21
Capitalized Information Servces
(f)
4,718,000
22
Tax Loss - Sale of Assets
(g)
18,903,000
23
Tax Repairs/PP&E Cost Adj
(h)
85,842,000
24
Other
(i)(j)
54,842,318
26
(k)
655,069,138
27
Federal Tax Net Income
489,181,674
28
Show Computation of Tax:
29
Federal Income Tax at 21%
102,728,152
30
Add: Adjustment of Prior Year
4,541,013
31
Add: Rounding
139
32
Balance, Federal Income Tax
98,187,000
33
Less: Amounts charged to Other Income and Deductions (409.2)
682,000
34
Less: Amounts charged to Gas Plant Leased to Others (409.1)
35
Amount Charged to Utility Operating Income (409.1)
97,505,000


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DeductionsRecordedOnBooksNotDeductedForReturn

 

263A INTEREST

$

53,431,000

ASSET RETIREMENT OBLIGATIONS

 

28,983,000

LIABILITIES – OTHER

 

442,000

NONDEDUCTIBLE EXPENSE

 

2,462,000

OTHER DEFERRED CHARGES – ARO TRUST FUND

 

9,240,000

REGULATORY ASSET – OTHER

 

5,057,000

REGULATORY LIABILITY – RETIREE MEDICAL & LIFE & PBOP DEF COLL

 

16,029,000

REGULATORY LIABILITY – FAS 106

 

5,907,000

REGULATORY LIABILITY – OTHER

 

249,000

 

$

121,800,000

(b) Concept: IncomeRecordedOnBooksNotIncludedInReturn
Original value: -87111000
(c) Concept: IncomeRecordedOnBooksNotIncludedInReturn
Original value: -661000
(d) Concept: IncomeRecordedOnBooksNotIncludedInReturn
Original value: -87772000
(e) Concept: DeductionsOnReturnNotChargedAgainstBookIncome
Original value: -490763820
(f) Concept: DeductionsOnReturnNotChargedAgainstBookIncome
Original value: -4718000
(g) Concept: DeductionsOnReturnNotChargedAgainstBookIncome
Original value: -18903000
(h) Concept: DeductionsOnReturnNotChargedAgainstBookIncome
Original value: -85842000
(i) Concept: DeductionsOnReturnNotChargedAgainstBookIncome

 

ASSETS – OTHER

$

(62,000)

CONTINGENCIES

 

(184,000)

DEFERRED STATE INCOME TAXES

 

(18,331,318)

DEFERRED REVENUE – NC TRANS PREPAY

 

(966,000)

ENVIRONMENTAL LIABILITIES

 

(528,000)

PREPAID INSURANCE / PREPAID OTHER

 

(7,473,000)

PROJECT FEASIBILITY COSTS

 

(29,000)

REGULATORY ASSET – FUEL TRACKER

 

(322,000)

REGULATORY LIABILITY – ELECTRIC POWER CARRYING CHARGE

 

(13,231,000)

TAX EXEMPT INTEREST

 

(1,358,000)

 

$

(54,842,318)

(j) Concept: DeductionsOnReturnNotChargedAgainstBookIncome
Original value: -54842318
(k) Concept: DeductionsOnReturnNotChargedAgainstBookIncome
Original value: -655069138

Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
  1. Give details of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts.
  2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes). Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes.
  3. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b) amounts credited to the portion of prepaid taxes charged to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts.
  4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
  5. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d).
  6. Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a footnote. Designate debit adjustments by parentheses.
  7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority.
  8. Show in columns (l) thru (s) how the taxes accounts were distributed. Show both the utility department and number of account charged. For taxes charged to utility plant, show the number of the appropriate balance sheet plant account or subaccount.
  9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
  10. Items under $250,000 may be grouped.
  11. Report in column (t) the applicable effective state income tax rate.
Line No.
DescriptionOfTaxesAccruedPrepaidAndCharged
Kind of Tax (See Instruction 5)
(a)
TypeOfTax
Type of Tax
(b)
TaxJurisdiction
Tax Jurisdiction
(c)
TaxYear
Tax Year
(d)
TaxesAccrued
Balance at Beg. of Year Taxes Accrued
(e)
PrepaidTaxes
Balance at Beg. of Year Prepaid Taxes
(f)
TaxesCharged
Taxes Charged During Year
(g)
TaxesPaid
Taxes Paid During Year
(h)
TaxAdjustments
Adjustments
(i)
TaxesAccrued
Balance at End of Year Taxes Accrued (Account 236)
(j)
PrepaidTaxes
Balance at End of Year Prepaid Taxes (Included in Acct 165)
(k)
TaxesAccruedPrepaidAndCharged
Electric (Account 408.1, 409.1)
(l)
TaxesAccruedPrepaidAndCharged
Gas (Account 408.1, 409.1)
(m)
TaxesAccruedPrepaidAndCharged
Other Utility Dept. (Account 408.1, 409.1)
(n)
OtherIncomeAndDeductions
Other Income and Deductions (Account 408.2, 409.2)
(o)
IncomeTaxesExtraordinaryItems
Extraordinary Items (Account 409.3)
(p)
OtherUtilityOperatingIncomeAssociatedWithTaxesOtherThanIncomeTaxes
Other Utility Opn. Income (Account 408.1, 409.1)
(q)
AdjustmentsToRetainedEarnings
Adjustment to Ret. Earnings (Account 439)
(r)
TaxesIncurredOther
Other
(s)
StateLocalIncomeTaxRate
State/Local Income Tax Rate
(t)
1
Federal Income
98,187,000
97,392,000
795,000
97,505,000
682,000
2
Total Federal
98,187,000
97,392,000
795,000
97,505,000
682,000
3
FICA
5,830,833
5,830,833
5,830,833
4
Federal Unemployment
61,009
61,009
61,009
5
Federal Medical
2,354,711
2,354,711
2,354,711
6
Alabama - Unemployment
5,043
5,043
5,043
7
Colorado - Unemployment
78
78
78
8
Florida - Unemployment
124
124
124
9
Georgia - Unemployment
6,494
6,494
6,494
10
Kansas - Unemployment
11
Kentucky - Unemployment
12
Louisiana - Unemployment
1,108
1,108
1,108
13
Maryland - Unemployment
663
663
663
14
Mississippi - Unemployment
1,670
1,670
1,670
15
New Mexico - Unemployment
16
North Carolina - Unemployment
1,329
1,329
17
New Jersey - Unemployment
27,280
27,280
1,329
18
New York - Unemployment
525
525
27,280
19
Ohio - Unemployment
525
20
Oklahoma - Unemployment
21
Pennsylvania - Unemployment
114,282
114,282
22
South Carolina - Unemployment
269
269
114,282
23
Texas - Unemployment
291,863
291,863
269
24
Utah - Unemployment
291,863
25
Virginia - Unemployment
3,264
3,264
26
Washington - Unemployment
175
175
3,264
27
West Virginia - Unemployment
175
28
Wyoming - Unemployment
29
TOTAL PAYROLL
8,700,720
8,700,720
8,700,720
30
Alabama - Income
2,517,000
937,000
661,000
919,000
2,517,000
0.91
31
California - Income
32
Colorado - Income
722,000
722,000
722,000
33
Delaware - Income
34
Florida - Income
60,000
60,000
60,000
35
Georgia - Income
1,341,000
525,000
301,000
515,000
1,341,000
0.51
36
Idaho - Income
180,000
180,000
180,000
37
Illinois - Income
90,000
90,000
90,000
38
Kansas - Income
722,000
722,000
722,000
39
Louisiana - Income
4,569,000
893,000
2,794,000
882,000
4,569,000
0.87
40
Maryland - Income
926,000
422,000
90,000
414,000
926,000
0.41
41
Mississippi - Income
761,000
247,000
271,000
243,000
761,000
0.24
42
New Jersey - Income
2,062,000
814,000
451,000
797,000
2,062,000
0.79
43
New Mexico - Income
211,000
211,000
211,000
44
New York - Income
1,026,000
381,000
271,000
374,000
1,026,000
0.37
45
New York City - Income
803,000
299,000
211,000
293,000
803,000
0.29
46
North Carolina - Income
508,000
196,000
121,000
191,000
508,000
0.19
47
North Dakota - Income
121,000
121,000
121,000
48
Oklahoma - Income
240,000
240,000
240,000
49
Oregon - Income
180,000
180,000
180,000
50
Pennsylvania - Income
6,089,000
1,328,000
3,458,000
1,303,000
6,089,000
1.29
51
South Carolina - Income
631,000
258,000
121,000
252,000
631,000
0.25
52
Texas - Income
130,000
352,000
206,000
428,000
352,000
0.01
53
Utah - Income
60,000
60,000
60,000
54
Virginia - Income
1,198,000
484,000
240,000
474,000
1,198,000
0.47
55
West Virginia - Income
1,504,000
1,504,000
1,504,000
56
TOTAL STATE/CITY INCOME
130,000
26,873,000
6,578,000
13,080,000
7,085,000
26,873,000
6.6
57
Alabama - Use
9,594
1,140,411
887,343
262,662
1,140,411
58
Florida - Use
59
Georgia - Use
9,889
459,360
454,224
4,753
459,360
60
Georgia - Use Audit
61
Louisiana - Use
186,500
1,784,896
1,794,881
176,515
487,640
25,903
1,271,353
62
Louisiana - Use Audit
63
Maryland - Use
22,161
99,653
115,104
6,710
99,653
64
Mississippi - Use
20,543
570,975
575,783
15,735
72,017
498,958
65
North Carolina - Use
46,530
506,260
554,588
1,798
506,260
66
New Jersey - Use
89,090
193,277
216,381
65,986
193,277
67
New York - Use
1,377
1,412,192
10,400
1,403,169
1,412,192
68
Oklahoma - Use
111
561
672
561
69
Pennsylvania - Use
44,329
378,639
357,232
65,736
378,639
70
South Carolina - Use
8,246
459,715
462,417
5,544
459,715
71
Texas - Use
154,534
2,502,507
2,563,407
93,634
2,502,479
72
Texas - Use Audit
28
73
Virginia - Use
142,852
1,510,937
1,613,465
40,324
1,510,937
74
Miscellaneious - Use
2,755
2,755
75
TOTAL USE
715,978
11,019,383
9,605,225
2,130,136
559,657
28,686
(a)
10,431,040
76
Alabama - Property
4,618,928
4,618,928
4,618,928
77
Georgia - Property
2,433,421
3,648,564
3,172,276
2,909,709
3,648,564
78
Louisiana - Property
11,228,348
11,228,348
11,228,348
79
Maryland - Property
2,830,318
2,830,318
2,830,318
80
Mississippi - Property
4,496,477
4,500,589
4,496,927
4,500,139
4,500,589
81
New Jersey - Property
395,023
11,742,612
11,387,072
39,483
11,742,612
82
New Mexico - Property
83
New York - Property
14,805
17,125,383
17,140,188
17,125,383
84
North Carolina - Property
1,825,592
1,825,592
1,825,592
85
Oklahoma - Property
86
Pennsylvania - Property
482,004
481,999
5
482,004
87
South Carolina - Property
2,954,058
3,291,252
2,954,445
3,290,865
3,291,252
88
Texas - Property
2,613,517
2,857,249
2,835,405
2,635,361
2,857,249
89
Virginia - Property
10,176
2,782,786
2,791,666
1,296
2,782,786
90
TOTAL PROPERTY
12,127,431
66,933,625
65,763,164
13,297,892
66,933,625
91
Alabama - Francise
15,000
15,000
15,000
92
Pennsylvania - Francise
93
TOTAL FRANCISE
15,000
15,000
15,000
94
LA Severance Tax Settlement
95
TOTAL
40
Total
12,713,409
211,728,728
90,662,109
110,472,000
23,308,028
200,587,002
28,686
682,000
10,431,040


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: TaxesIncurredOther

 

 

 

Account

 

 

10701001

$ 9,009,871

 

 

10898001

284

 

 

16300003

18

 

 

16300009

246,461

 

 

18320001

21,908

 

 

18608001

81,805

 

 

23201023

14

 

 

75300001

407

 

 

75900001

453

 

 

81400001

1,271

 

 

81600001

4,450

 

 

81700001

103

 

 

81801001

18,286

 

 

83200001

937

 

 

83401001

16,888

 

 

83600001

39,747

 

 

83700003

29

 

 

84101002

28,064

 

 

85000001

9,237

 

 

85200001

2,516

 

 

85300101

284,149

 

 

85600001

329,746

 

 

85700001

13,530

 

 

85900001

118,461

 

 

86000001

71

 

 

86201101

25,827

 

 

86301001

11,445

 

 

86401001

181,519

 

 

86501001

1,055

 

 

86600001

1

 

 

86700001

1,483

 

 

92100001

293

 

 

92300001

3,153

 

 

84371001

2,529

 

 

85900101

1,972

 

 

16300006

1,176

 

 

85600008

586

 

 

40816001

(2,754)

 

 

40813001

(150)

 

 

40813001

(28)

 

 

40813002

(25,753)

 

 

23602001

(19)

 

 

TOTAL

$ 10,431,040


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Miscellaneous Current and Accrued Liabilities (Account 242)
  1. Describe and report the amount of other current and accrued liabilities at the end of year.
  2. Minor items (less than $250,000) may be grouped under appropriate title.
Line No.
DescriptionOfMiscellaneousCurrentAndAccruedLiabilities
Item
(a)
MiscellaneousCurrentAndAccruedLiabilities
Balance at End of Year
(b)
1
LGA/LGS Storage Pricing Differential
3,848,314
2
Transportation and Exchange Gas Imbalance
5,972,516
3
Reserve for Proposed Civil Penalty
1,795,400
4
Accrued Estimated Environmental Cost
1,468,000
5
Prepaid Firm Transportation
966,666
45
Total
14,050,896


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Other Deferred Credits (Account 253)
  1. Report below the details called for concerning other deferred credits.
  2. For any deferred credit being amortized, show the period of amortization.
  3. Minor items (less than $250,000) may be grouped by classes.
Line No.
DescriptionOfOtherDeferredCredits
Description of Other Deferred Credits
(a)
OtherDeferredCredits
Balance at Beginning of Year
(b)
DecreaseInOtherDeferredCreditsContraAccount
Debit Contra Account
(c)
DecreaseInOtherDeferredCredits
Debit Amount
(d)
IncreaseInOtherDeferredCredits
Credits
(e)
OtherDeferredCredits
Balance at End of Year
(f)
1
Self-Insurance General Liability
289,955
108,469
187,761
369,247
2
63,050
63,050
3
Estimated Environmental Cost
2,165,000
483,458
310,458
1,992,000
4
Minimum Lease Obligation
850,120
261,576
588,544
5
(Through March 2021)
6
Lease Commission Reimbursement
701,638
701,638
7
(Through March 2031)
8
Transportation Prepayments
10,871,457
965,790
9,905,667
9
Suspense Projects
1,932,944
2,089,225
4,022,169
10
Rockaway/NPS Reserve
314,430
197,384
98,000
215,046
11
Other
223,111
883,436
757,612
97,287
45
TOTAL
16,647,017
2,963,163
4,144,694
17,828,548


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
Accumulated Deferred Income Taxes-Other Property (Account 282)
  1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to property not subject to accelerated amortization.
  2. At Other (Specify), include deferrals relating to other income and deductions.
  3. Provide in a footnote a summary of the type and amount of deferred income taxes reported in the beginning-of-year and end-of-year balances for deferred income taxes that the respondent estimates could be included in the development of jurisdictional recourse rates.
Line No.
Account Subdivisions
(a)
Balance at Beginning of Year
(b)
Changes During Year Amounts Debited to Account 410.1
(c)
Changes During Year Amounts Credited to Account 411.1
(d)
Changes During Year Amounts Debited to Account 410.2
(e)
Changes During Year Amounts Credited to Account 411.2
(f)
Adjustments Debits Account No.
(g)
Adjustments Debits Amount
(h)
Adjustments Credits Account No.
(i)
Adjustments Credits Amount
(j)
Balance at End of Year
(k)
1
Account 282
2
Electric
3
Gas
1,276,602,664
291,781,000
68,552,000
1,499,831,664
4
Other (Define)
5
Total (Total of lines 2 thru 4)
1,276,602,664
291,781,000
68,552,000
1,499,831,664
6
Other (Specify)
7
TOTAL Account 282 (Total of lines 5 thru 6)
1,276,602,664
291,781,000
68,552,000
(a)
1,499,831,664
8
Classification of TOTAL
9
Federal Income Tax
1,007,866,414
148,269,000
33,923,000
1,122,212,414
10
State Income Tax
268,736,250
143,512,000
34,629,000
377,619,250
11
Local Income Tax


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOtherProperty

 

 

 

 

 

 

 

 

 

 

DEF

 

 

 

 

 

 

 

 

TAX

 

 

 

 

 

 

 

 

ACCT

12/31/2018

 

12/31/2018

 

 

 

12/31/2018

 

& CTD

TOTAL

 

CTD’S

 

NOT IN

 

ADJUSTED

 

TYPE

CTD’S

 

@0.2621

 

RATE BASE

 

ADIT

 

 

 

 

 

 

 

 

 

PP&E COST ADJ – SOFTWARE DEVELOP

282 NC

(250,825,196)

 

(65,751,317)

 

-

 

(65,751,317)

PP&E COST ADJ – SMART PIGGING

282 NC

(91,944,745)

 

(24,102,395)

 

-

 

(24,102,395)

INT EXP-AFUDC EQUITY-PP&E COST ADJ

282 NC

(486,472,646)

 

(127,523,939)

 

-

 

(127,523,939)

PP&E COST ADJ – ARO

282 NC

(116,040,011)

 

(30,422,930)

 

30,422,930

 

-

PP&E COST ADJ – OTHER

282 NC

(9,763,775)

 

(2,559,476)

 

-

 

(2,559,476)

PP&E COST ADJ – TAX REPAIR

282 NC

(1,354,873,812)

 

(355,166,621)

 

-

 

(355,166,621)

BOOK DEPRECIATION

282 NC

6,698,800,663

 

1,756,023,606

 

(6,277,589)

 

1,749,746,017

TAX DEPRECIATION

282 NC

(9,846,413,246)

 

(2,581,138,768)

 

60,757,583

 

(2,520,381,185)

TAX DEPRECIATION - STEPUP

283 NC

(184,371,506)

 

(48,331,147)

 

48,331,147

 

-

PP&E DEPRECIATION ADJ – ARO

282 NC

26,622,739

 

6,978,885

 

(6,978,885)

 

-

ARO COST OF REMOVAL 481(a) ADJ

282 NC

(56,621,037)

 

(14,842,639)

 

14,842,639

 

-

BOOK GAIN/LOSS – SALE PP&E

282 NC

(12,763,026)

 

(3,345,700)

 

-

 

(3,345,700)

TAX GAIN/LOSS – SALE PP&E

282 NC

(54,595,540)

 

(14,311,675)

 

-

 

(14,311,675)

TAX GAIN/LOSS SEC 481A ADD BACK

282 NC

17,786,116

 

4,662,452

 

-

 

4,662,452

 

 

(5,721,475,022)

 

(1,499,831,664)

 

141,097,825

 

(1,358,733,839)


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
Accumulated Deferred Income Taxes-Other (Account 283)
  1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283.
  2. At Other (Specify), include deferrals relating to other income and deductions.
  3. Provide in a footnote a summary of the type and amount of deferred income taxes reported in the beginning-of-year and end-of-year balances for deferred income taxes that the respondent estimates could be included in the development of jurisdictional recourse rates.
Line No.
Account Subdivisions
(a)
Balance at Beginning of Year
(b)
Changes During Year Amounts Debited to Account 410.1
(c)
Changes During Year Amounts Credited to Account 411.1
(d)
Changes During Year Amounts Debited to Account 410.2
(e)
Changes During Year Amounts Credited to Account 411.2
(f)
Adjustments Debits Account No.
(g)
Adjustments Debits Amount
(h)
Adjustments Credits Account No.
(i)
Adjustments Credits Amount
(j)
Balance at End of Year
(k)
1
Account 283
2
Electric
3
Gas
80,344,503
46,024,945
130,513,602
135,376,235
5,657,578
125,574,503
4
Other (Define)
5
Total (Total of lines 2 thru 4)
80,344,503
46,024,945
130,513,602
135,376,235
5,657,578
125,574,503
6
Other (Specify)
7
TOTAL Account 283 (Total of lines 5 thru 6)
80,344,503
46,024,945
130,513,602
135,376,235
5,657,578
(a)
125,574,503
8
Classification of TOTAL
9
Federal Income Tax
63,430,411
34,148,291
8,920,407
9,532,047
4,232,931
93,957,411
10
State Income Tax
16,914,092
11,876,654
121,593,195
125,844,188
1,424,647
31,617,092
11
Local Income Tax


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther

 

 

DEF

 

 

 

 

 

TAX

 

 

 

 

 

ACCT

12/31/2018

12/31/2018

 

12/31/2018

 

& CTD

TOTAL

CTD’S

NOT IN

ADJUSTED

 

TYPE

CTD’S

@0.3825

RATE BASE

ADIT

 

 

 

 

 

 

BOOK GAIN/LOSS - ARO TRUST FUND

283 NC

$ (5,064,547)

$ (1,327,620)

$ 1,327,620

$ -

TAX GAIN/LOSS - ARO TRUST FUND 109

283 NC

5,075,358

1,330,454

(1,330,454)

-

PREPAID INSURANCE – DEFAULT

283 NC

(592,396)

(155,291)

155,291

-

PREPAID INSURANCE – PROPERTY

283 NC

(3,934,505)

(1,031,391)

1,031,391

-

PREPAID INSURANCE – EXCESS LIAB

283 NC

(2,946,313)

(772,346)

772,346

-

PREPAID FERC ACA FEES – OTH ASSETS

283 NC

(3,741,356)

(980,759)

980,759

-

OTH ASSETS - CURR-SPECIAL DEPOSITS

283 NC

(57,330)

(15,028)

15,028

-

OTHER DEF CHRGS-ARO TSTFD UNREAL G/L

283 NC

(9,451,485)

(2,477,612)

2,477,612

-

OTH ASSET-NCURR-PROJ FEASIBILITY COST

283 NC

490,362

128,543

(128,543)

-

REG ASSET-CURR-DEF TAX – RATE BASE

283 NC

(1,077,783)

(282,530)

-

(282,530)

REG ASSET-CURR-FTRKR LNG

283 NC

(1,120,307)

(293,677)

293,677

-

REG ASSET-CURR-FTRKR CC LNG

283 NC

(143,648)

(37,656)

37,656

-

REG ASSET-CURR-FTRKR-TRAN DEF

283 NC

(48,353,230)

(12,675,316)

12,675,316

-

REG ASSET-CURR-FTRKR TRAN-CC STOR

283 NC

(1,055,190)

(276,608)

276,608

-

REG ASSET-CURR-ARO-EMINENCE

283 NC

(4,856,500)

(1,273,083)

1,273,083

-

REG ASSET-CURR-FTRKR STORAGE DEF

283 NC

(10,127,986)

(2,654,950)

2,654,950

-

REG ASSET-CURR-FTRKR-CC TRAN

283 NC

(2,120,299)

(555,815)

555,815

-

REG ASSET-CURR-ASSET RET OBL

283 NC

(28,615,028)

(7,501,143)

7,501,143

-

REG LIAB-CURR-OFO RESERVE PENALTY

283 NC

2,390,450

626,633

(626,633)

-

REG LIAB –CURR-ELEC PWR DEF DEMND

283 NC

(1,315,103)

(344,741)

344,741

-

REG LIAB-NC-SENTINEL EXPENSE

283 NC

102,369

26,835

(26,835)

-

REG LIAB-CURR-RETIREE MED LIFE FAS 106

283 NC

2,542,305

666,440

(666,440)

-

REG LIAB-CURR-TRANS OVERRUN

283 NC

1,720

451

(451)

-

REG LIAB-CURR-ELEC PWR CARRYING CHG

283 NC

1,367,145

358,383

(358,383)

-

REG LIAB-CURR-DEFAULT-UNAUTH TAKE DEF

283 NC

8,615

2,258

(2,258)

-

REG ASSET NC-DEF TAX-RATE BASE

283 NC

(1,602,343)

(420,038)

-

(420,038)

REG ASSET-NC-ARO-EMINENCE

283 NC

(40,632,422)

(10,651,383)

10,651,383

-

REG ASSET NC-ARO TRUST WITHD DEF

283 NC

(1,252,730)

(328,391)

328,391

-

REG ASSET NC-CASHOUT DEFERRAL

283 NC

(54,865,680)

(14,382,489)

14,382,489

-

INT EXP-REG ASSET-AFUDC EQUITY

283 NC

(156,784,917)

(41,099,598)

-

(41,099,598)

REG ASSET-NC-ARO

283 NC

(142,024,629)

(37,230,624)

37,230,624

-

REG LIAB-NC-DEFAULT FAS 106

283 NC

54,359,330

14,249,755

(14,249,755)

-

REG LIAB NC-DEF GAS COST

283 NC

(4,031,755)

(1,056,884)

1,056,884

-

REG ASSET – DEFERRED TAX RATE BASE 2018

283 NC

(85,189,830)

(22,331,662)

-

(22,331,662)

REG LIAB-NC-SENTINEL EXPENSE

283 NC

6,341,876

1,662,459

(1,662,459)

-

REG LIAB-NC-PBOP DEF COLL

283 NC

22,942,198

6,014,068

(6,014,068)

-

REG LIAB-NC-PENSION DEF COLL

283 NC

48,548,036

12,726,382

(12,726,382)

-

PP&E COST ADJ-MISC (734B)

283 NC

8,543,576

2,239,613

(2,239,613)

-

TAX DEPRECIATION (734B)

283 NC

(21,027,881)

(5,512,249)

5,512,249

-

TAX GAIN/LOSS-SALE PP&E (734B)

283 NC

236,922

62,107

(62,107)

-

 

 

$ (479,034,931)

$ (125,574,503)

$ 61,440,674

$(64,133,829)


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Other Regulatory Liabilities (Account 254)
  1. Report below the details called for concerning other regulatory liabilities which are created through the ratemaking actions of regulatory agencies (and not includable in other amounts).
  2. For regulatory liabilities being amortized, show period of amortization in column (a).
  3. Minor items (5% of the Balance at End of Year for Account 254 or amounts less than $250,000, whichever is less) may be grouped by classes.
  4. Provide in a footnote, for each line item, the regulatory citation where the respondent was directed to refund the regulatory liability (e.g. Commission Order, state commission order, court decision).
Line No.
DescriptionAndPurposeOfOtherRegulatoryLiabilities
Description and Purpose of Other Regulatory Liabilities
(a)
OtherRegulatoryLiabilities
Balance at Beginning of Current Quarter/Year
(b)
OtherRegulatoryLiabilityAccountOffsettingCredits
Written off during Quarter/Period Account Credited
(c)
OtherRegulatoryLiabilityWrittenOffRefunded
Written off During Period Amount Refunded
(d)
OtherRegulatoryLiabilityWrittenOffDeemedNonRefundable
Written off During Period Amount Deemed Non-Refundable
(e)
OtherRegulatoryLiabilityAdditions
Credits
(f)
OtherRegulatoryLiabilities
Balance at End of Current Quarter/Year
(g)
1
Deferred Collections - Post Retirement
2
(a)
Benefits Other Than Pensions
65,431,312
8,449,444
73,880,756
3
Unamortized Payable - Post Retirement
4
Benefits Other Than Pensions
5
(b)
(03/2013 - 05/2021)
8,505,383
2,542,305
5,963,078
6
Sentinel Meter Station Depreciation
7
Expense
8
(c)
(07/2014 - 10/2063)
6,295,570
102,368
251,044
6,444,246
9
(d)
Overrun Penalty Revenue Sharing
347,033
319,401
27,632
10
25,912
25,912
11
(e)
Operational Flow Order Penalty Deferral
22,200
2,412,650
2,390,450
12
(f)
Unauthorized Takes
76,127
72,973
5,461
8,615
13
Electric Power Trackers and Carrying
14
(g)
Costs
13,282,244
16,282,909
3,052,478
51,813
15
Collections in Excess of Pension
16
(h)
Funding Obligation
32,518,947
16,029,089
48,548,036
17
(i)
Deferred Tax Rate Base
840,396,422
36,415,410
803,981,012
18
(j)
Deferred Gas Cost
168,408
1,939,707
2,108,115
45
Total
966,684,630
57,723,185
32,308,281
941,269,726


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

DOCKET NO. RP 12-993

(b) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

DOCKET NO. RP 12-993, DEFERRED BALANCE TRANSFERRED TO BE AMORTIZED OVER 8.2 YEARS

(c) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

DOCKET NO. CP08-31-001

DOCKET NO. CP08-31-002

(d) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 54

(e) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 54

(f) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 54

(g) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 41.5

(h) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

DOCKET NO. RP 12-993

(i) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

RELATES TO THE ESTABLISHMENT OF A REGULATORY LIABILITY AS A RESULT OF THE TAX CUT AND JOBS ACT ENACTED ON DECEMBER 22, 2017

(j) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

 

FERC GAS TARIFF GENERAL TERMS AND CONDITIONS SECTION 54


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Monthly Quantity & Revenue Data by Rate Schedule
  1. Reference to account numbers in the USofA is provided in parentheses beside applicable data. Quantities must not be adjusted for discounts.
  2. Total Quantities and Revenues in whole numbers.
  3. Report revenues and quantities of gas by rate schedule. Where transportation services are bundled with storage services, reflect only transportation Dth. When reporting storage, report Dth of gas withdrawn from storage and revenues by rate schedule.
  4. Revenues in Column (c) include transition costs from upstream pipelines. Revenue (Other) in Column (e) includes reservation charges received by the pipeline plus usage charges, less revenues reflected in Columns (c) and (d). Include in Column (e), revenue for Accounts 490-495.
  5. Enter footnotes as appropriate.
Line No.
Item
(a)
Month 1 Quantity
(b)
Month 1 Revenue Costs and Take-or-Pay
(c)
Month 1 Revenue (GRI & ACA)
(d)
Month 1 Revenue (Other)
(e)
Month 1 Revenue (Total)
(f)
Month 2 Quantity
(g)
Month 2 Revenue Costs and Take-or-Pay
(h)
Month 2 Revenue (GRI & ACA)
(i)
Month 2 Revenue (Other)
(j)
Month 2 Revenue (Total)
(k)
Month 3 Quantity
(l)
Month 3 Revenue Costs and Take-or-Pay
(m)
Month 3 Revenue (GRI & ACA)
(n)
Month 3 Revenue (Other)
(o)
Month 3 Revenue (Total)
(p)
1
Total Sales (480-488)
62,250
12,398
12,398
20,622
7,509
7,509
3,390
3,390
2
Transportation of Gas for Others (489.2 and 489..3)
3
FDLS
8,144,550
10,588
5,775,333
5,785,921
7,376,891
9,590
5,588,855
5,598,445
8,171,975
10,624
5,775,157
5,785,781
4
FT
382,984,361
413,809
158,681,623
159,095,432
378,254,406
429,421
161,944,559
162,373,980
403,115,109
452,235
170,083,908
170,536,143
5
FTG
20
8
8
14,506
19
5,780
5,799
13,243
17
5,277
5,294
6
FTP
300,716
37,887
37,887
373,529
47,061
47,061
374,346
47,164
47,164
7
ICTS
5,318,117
153,915
153,915
5,778,698
87,637
87,637
6,192,004
100,481
100,481
8
IT
21,134,195
9,836
1,813,788
1,823,624
23,216,794
9,505
1,950,017
1,959,522
22,385,752
10,470
1,743,859
1,754,329
9
Other
153,503
153,503
81,347
81,347
103,089
103,089
63
Total Transportation (Other than Gathering)
417,881,959
434,233
166,616,057
167,050,290
415,014,824
448,535
169,705,256
170,153,791
440,252,429
473,346
177,858,935
178,332,281
64
Storage (489.4)
65
10,051
10,051
9,727
9,727
10,051
10,051
66
487,407
1,436,817
1,436,817
708,950
1,288,146
1,288,146
491,871
1,454,878
1,454,878
67
317,360
4,788,994
4,788,994
5,876,413
4,646,863
4,646,863
5,582,963
4,759,062
4,759,062
68
98,499
98,499
2,887
95,058
95,058
1,861
98,178
98,178
69
766,945
766,945
738,349
738,349
778,753
778,753
70
972,259
972,259
882,489
938,370
938,370
2,645,749
1,175,887
1,175,887
71
650,490
650,490
739,246
664,820
664,820
1,959,193
723,720
723,720
72
1,197,564
1,197,564
497,559
1,170,408
1,170,408
1,228,839
1,556,686
1,556,686
73
3,721,732
1,395,825
1,395,825
7,745,729
1,383,262
1,383,262
10,722,517
1,465,735
1,465,735
74
1,593
1,593
540
540
2,052
2,052
90
Total Storage
4,526,499
11,319,037
11,319,037
16,453,273
10,934,463
10,934,463
22,632,993
12,020,898
12,020,898
91
Gathering (489.1)
92
Gathering-Firm
93
Gathering-Interruptible
830,015
220,560
220,560
766,162
202,629
202,629
848,362
227,876
227,876
94
Total Gathering (489.1)
830,015
220,560
220,560
766,162
202,629
202,629
848,362
227,876
227,876
95
Additional Revenues
96
Products Sales and Extraction (490-492)
97
Rents (493-494)
5,000
5,000
98
(495) Other Gas Revenues
3,707,664
11,202,933
11,202,933
3,427,784
10,246,360
10,246,360
2,206,292
14,642,923
14,642,923
99
(496) (Less) Provision for Rate Refunds
100
Total Additional Revenues
3,707,664
11,202,933
11,202,933
3,427,784
10,251,360
10,251,360
2,206,292
14,642,923
14,642,923
101
Total Operating Revenues (Total of Lines 1,63,90,94 & 100)
427,008,387
434,233
189,370,985
189,805,218
435,682,665
448,535
191,101,217
191,549,752
465,940,076
473,346
204,754,022
205,227,368


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Gas Operating Revenues
  1. Report below natural gas operating revenues for each prescribed account total. The amounts must be consistent with the detailed data on succeeding pages.
  2. Revenues in columns (b) and (c) include transition costs from upstream pipelines.
  3. Other Revenues in columns (f) and (g) include reservation charges received by the pipeline plus usage charges, less revenues reflected in columns (b) through (e). Include in columns (f) and (g) revenues for Accounts 480-495.
  4. If increases or decreases from previous year are not derived from previously reported figures, explain any inconsistencies in a footnote.
  5. On Page 108, include information on major changes during the year, new service, and important rate increases or decreases.
  6. Report the revenue from transportation services that are bundled with storage services as transportation service revenue.
Line No.
Title of Account
(a)
Revenues for Transition Costs and Take-or-Pay Amount for Current Year
(b)
Revenues for Transaction Costs and Take-or-Pay Amount for Previous Year
(c)
Revenues for GRI and ACA Amount for Current Year
(d)
Revenues for GRI and ACA Amount for Previous Year
(e)
Other Revenues Amount for Current Year
(f)
Other Revenues Amount for Previous Year
(g)
Total Operating Revenues Amount for Current Year
(h)
Total Operating Revenues Amount for Previous Year
(i)
Dekatherm of Natural Gas Amount for Current Year
(j)
Dekatherm of Natural Gas Amount for Previous Year
(k)
1
ResidentialSalesAbstract
(480) Residential Sales
2
CommercialAndIndustrialSalesAbstract
(481) Commercial and Industrial Sales
3
OtherSalesToPublicAuthoritiesAbstract
(482) Other Sales to Public Authorities
4
SalesForResaleAbstract
(483) Sales for Resale
5
InterdepartmentalSalesAbstract
(484) Interdepartmental Sales
6
IntracompanyTransfersAbstract
(485) Intracompany Transfers
7
ForfeitedDiscountsAbstract
(487) Forfeited Discounts
63,108
41,782
63,108
41,782
8
MiscellaneousServiceRevenuesAbstract
(488) Miscellaneous Service Revenues
22,429
972,358
22,429
972,358
9
RevenuesFromTransportationOfGasOfOthersThroughGatheringFacilitiesAbstract
(489.1) Revenues from Transportation of Gas of Others Through Gathering Facilities
3,112,622
4,213,059
3,112,622
4,213,059
11,734,451
15,899,623
10
RevenuesFromTransportationOfGasOfOthersThroughTransmissionFacilitiesAbstract
(489.2) Revenues from Transportation of Gas of Others Through Transmission Facilities
5,109,502
4,524,790
1,764,180,046
1,530,914,030
1,769,289,548
1,535,438,820
5,525,098,298
5,139,205,113
11
RevenuesFromTransportationOfGasOfOthersThroughDistributionFacilitiesAbstract
(489.3) Revenues from Transportation of Gas of Others Through Distribution Facilities
12
RevenuesFromStoringGasOfOthersAbstract
(489.4) Revenues from Storing Gas of Others
136,666,418
137,349,929
136,666,418
137,349,929
145,179,267
133,444,295
13
SalesOfProductsExtractedFromNaturalGasAbstract
(490) Sales of Prod. Ext. from Natural Gas
14
RevenuesFromNaturalGasProcessedByOthersAbstract
(491) Revenues from Natural Gas Proc. by Others
15
IncidentalGasolineAndOilSalesAbstract
(492) Incidental Gasoline and Oil Sales
16
RentFromGasPropertyAbstract
(493) Rent from Gas Property
17
InterdepartmentalRentsAbstract
(494) Interdepartmental Rents
18
OtherGasRevenuesAbstract
(495) Other Gas Revenues
116,800,905
111,217,464
116,800,905
111,217,464
19
OperatingRevenuesBeforeProvisionForRateRefundsAbstract
Subtotal:
5,109,502
4,524,790
2,020,845,528
1,784,708,622
2,025,955,030
1,789,233,412
20
ProvisionForRateRefundsAbstract
(496) (Less) Provision for Rate Refunds
2,137
2,137
21
OperatingRevenuesAbstract
TOTAL
5,109,502
4,524,790
2,020,845,528
1,784,706,485
2,025,955,030
1,789,231,275


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Revenues from Transporation of Gas of Others Through Gathering Facilities (Account 489.1)
  1. Report revenues and Dth of gas delivered through gathering facilities by zone of receipt (i.e. state in which gas enters respondent's system).
  2. Revenues for penalties including penalties for unauthorized overruns must be reported on page 308.
Line No.
ZoneOfDeliveryOrReceiptRateSchedule
Rate Schedule and Zone of Recipt
(a)
RevenuesForTransitionCostsAndTakeOrPay
Revenues for Transition Costs and Take-or-Pay Amount for Current Year
(b)
RevenuesForTransitionCostsAndTakeOrPay
Revenues for Transaction Costs and Take-or-Pay Amount for Previous Year
(c)
RevenuesFromGRIAndACA
Revenues for GRI and ACA Amount for Current Year
(d)
RevenuesFromGRIAndACA
Revenues for GRI and ACA Amount for Previous Year
(e)
OtherRevenues
Other Revenues Amount for Current Year
(f)
OtherRevenues
Other Revenues Amount for Previous Year
(g)
RevenuesFromTransportationOfGasOfOthersThroughGatheringFacilities
Total Operating Revenues Amount for Current Year
(h)
RevenuesFromTransportationOfGasOfOthersThroughGatheringFacilities
Total Operating Revenues Amount for Previous Year
(i)
DekathermOfNaturalGas
Dekatherm of Natural Gas Amount for Current Year
(j)
DekathermOfNaturalGas
Dekatherm of Natural Gas Amount for Previous Year
(k)
1
FT-4
156
156
588
2
IT-1
1,559,464
1,993,533
1,559,464
1,993,533
5,884,770
7,522,768
3
IT-2
1,000,371
1,411,091
1,000,371
1,411,091
3,774,984
5,324,868
4
IT-3
468,993
732,359
468,993
732,359
1,769,785
2,763,616
5
IT-4
80,646
76,418
80,646
76,418
304,324
288,371
6
OTHER
2,992
342
2,992
342
7
TOTAL
3,112,622
4,213,059
3,112,622
4,213,059
11,734,451
15,899,623


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Revenues from Transportation of Gas of Others Through Transmission Facilities (Account 489.2)
  1. Report revenues and Dth of gas delivered by Zone of Delivery by Rate Schedule. Total by Zone of Delivery and for all zones. If respondent does not have separate zones, provide totals by rate schedule.
  2. Revenues for penalties including penalties for unauthorized overruns must be reported on page 308.
  3. Other Revenues in columns (f) and (g) include reservation charges received by the pipeline plus usage charges for transportation and hub services, less revenues reflected in columns (b) through (e).
  4. Delivered Dth of gas must not be adjusted for discounting.
  5. Each incremental rate schedule and each individually certificated rate schedule must be separately reported.
  6. Where transportation services are bundled with storage services, report total revenues but only transportation Dth.
Line No.
ZoneOfDeliveryOrReceiptRateSchedule
Zone of Delivery, Rate Schedule
(a)
RevenuesForTransitionCostsAndTakeOrPay
Revenues for Transition Costs and Take-or-Pay Amount for Current Year
(b)
RevenuesForTransitionCostsAndTakeOrPay
Revenues for Transaction Costs and Take-or-Pay Amount for Previous Year
(c)
RevenuesFromGRIAndACA
Revenues for GRI and ACA Amount for Current Year
(d)
RevenuesFromGRIAndACA
Revenues for GRI and ACA Amount for Previous Year
(e)
OtherRevenues
Other Revenues Amount for Current Year
(f)
OtherRevenues
Other Revenues Amount for Previous Year
(g)
RevenuesFromTransportationOfGasOfOthersThroughTransmissionFacilities
Total Operating Revenues Amount for Current Year
(h)
RevenuesFromTransportationOfGasOfOthersThroughTransmissionFacilities
Total Operating Revenues Amount for Previous Year
(i)
DekathermOfNaturalGas
Dekatherm of Natural Gas Amount for Current Year
(j)
DekathermOfNaturalGas
Dekatherm of Natural Gas Amount for Previous Year
(k)
1
1, FT
14,849
16,382
46,586
136,517
61,435
152,899
13,553,980
14,203,097
2
1, GULF CONNECT(FT)
721
708,739
709,460
554,954
3
1, ICTS
6,630
62,649
6,630
62,649
132,600
1,252,985
4
1, IT
65,145
58,324
5,075,556
5,319,846
5,140,701
5,378,170
88,683,140
95,392,751
5
Subtotal Zone 1
80,715
74,706
5,837,511
5,519,012
5,918,226
5,593,718
102,924,674
110,848,833
6
2, FT
10,238
9,832
66,610
70,531
76,848
80,363
10,603,393
9,358,926
7
2, GULF TRACE(FT)
523,434
242,303
60,954,999
55,023,985
61,478,433
55,266,288
391,849,059
211,024,395
8
2, IT
6,932
10,591
1,013,937
1,303,871
1,020,869
1,314,462
10,572,682
14,799,165
9
Subtotal Zone 2
540,604
262,726
62,035,546
56,398,387
62,576,150
56,661,113
413,025,134
235,182,486
10
3, FT
88,807
46,951
2,032,100
3,772,985
2,120,907
3,819,936
213,004,882
175,423,150
11
3, GULF CONNECT(FT)
44
813
857
225,282
12
3, GULF TRACE(FT)
62,630
95,023
295,671
401,467
358,301
496,490
80,362,822
86,664,863
13
3, ICTS
383,129
364,745
383,129
364,745
7,662,571
14,428,304
14
3, IT
32,629
36,082
6,738,158
5,494,382
6,770,787
5,530,464
84,744,307
84,645,256
15
3, MOMENTUM(FT)
165
8,426
6,383
8,426
6,548
631,171
896,466
16
3, SUNBELT(FT)
18,244
10,145
18,244
10,145
3,486,895
1,407,452
17
3, SUNDANCE(FT)
1
1
245
18
Subtotal Zone 3
184,110
178,221
9,476,542
10,050,107
9,660,652
10,228,328
390,118,175
363,465,491
19
4, 85NORTH(FT)
49,290
32,659
7,767,627
7,673,994
7,816,917
7,706,653
37,915,264
25,122,531
20
4, ATL SUNRISE(FT)
21,829
2,824
66,780,341
9,803,444
66,802,170
9,806,268
20,292,611
4,233,740
21
4, CHEROKEE(FT)
19,064
12,157
9,470,988
9,349,805
9,490,052
9,361,962
14,733,755
9,387,429
22
4, DALTON(FT)
70,037
44,790
76,208,114
47,195,431
76,278,151
47,240,221
55,027,896
35,178,906
23
4, FT
263,772
199,644
30,835,124
30,526,156
31,098,896
30,725,800
370,366,898
245,740,082
24
4, FTG
94
46
28,588
14,219
28,682
14,265
71,428
35,344
25
4, FTP
2,590
35,091
2,590
35,091
20,000
269,703
26
4, HILLABEE(FT)
45,844,215
23,740,173
45,844,215
23,740,173
115,553,865
55,116,816
27
4, ICTS
1,375
327
1,375
327
27,501
6,532
28
4, IT
1,830
4,655
2,385,407
2,366,898
2,387,237
2,371,553
19,599,706
18,127,029
29
4, LEIDY SE(FT)
34,291
77,528
95,828,059
96,245,669
95,862,350
96,323,197
27,430,990
61,161,988
30
4, MID-SOUTH 2(FT)
41,346
42,258
13,446,391
13,537,444
13,487,737
13,579,702
31,804,458
32,506,126
31
4, MID-SOUTH(FT)
5,077
4,834
257,879
264,301
262,956
269,135
3,904,951
3,718,674
32
4, MOMENTUM(FT)
73,744
79,125
19,666,978
22,895,935
19,740,722
22,975,060
56,972,082
60,900,679
33
4, PASCAGOULA(FT)
69
216
285
53,000
34
4, SOUTHCOAST(FT)
68,443
62,269
15,012,668
15,086,800
15,081,111
15,149,069
52,645,798
48,090,254
35
4, SUNBELT(FT)
3,794
5,838
166,634
198,393
170,428
204,231
4,604,757
6,102,503
36
4, SUNDANCE(FT)
61,800
60,324
11,225,508
11,797,652
11,287,308
11,857,976
47,565,103
46,438,897
37
Subtotal Zone 4
714,480
628,951
394,928,702
290,731,732
395,643,182
291,360,683
858,590,063
652,137,233
38
4A, ATL SUNRISE(FT)
7,018,727
7,018,727
39
4A, FT
241,265
234,056
25,379,364
25,949,777
25,620,629
26,183,833
185,589,677
180,039,975
40
4A, FTP
19
15,240
15,259
14,600
41
4A, ICTS
674,807
431,607
674,807
431,607
20,168,707
12,288,431
42
4A, IT
3,000
967
250,952
96,916
253,952
97,883
2,307,440
744,071
43
4A, LEIDY SE(FT)
22
14,945,098
14,963,564
14,945,120
14,963,564
16,958
44
4A, MOBILEBAY S3(FT)
96,061
96,332
10,821,056
10,804,162
10,917,117
10,900,494
73,892,192
74,099,729
45
4A, PASCAGOULA(FT)
2,188
101
13,363,172
13,357,679
13,365,360
13,357,780
1,683,050
77,840
46
Subtotal Zone 4A
342,536
331,475
72,453,176
65,618,945
72,795,712
65,950,420
283,658,024
267,264,646
47
4B, FT
2,245
364
35,035
143,822
37,280
144,186
6,480,729
7,510,533
48
4B, FTP
898
158
625,905
648,091
626,803
648,249
4,959,252
5,112,665
49
4B, ICTS
578,968
688,609
578,968
688,609
41,616,792
52,525,040
50
4B, IT
5,101
883
3,429,213
3,818,672
3,434,314
3,819,555
37,741,121
41,766,267
51
Subtotal Zone 4B
8,244
1,405
4,669,121
5,299,194
4,677,365
5,300,599
90,797,894
106,914,505
52
5, 85NORTH(FT)
81,112
104,134
47,752,419
47,955,505
47,833,531
48,059,639
66,363,746
85,112,129
53
5, ATL SUNRISE(FT)
241,590
47,454
23,020,929
623,131
23,262,519
670,585
217,579,126
45,932,305
54
5, DALTON(FT)
78,279
72,894
958,440
1,010,480
1,036,719
1,083,374
74,726,040
88,690,913
55
5, FT
564,334
399,779
181,010,032
179,912,361
181,574,366
180,312,140
506,295,867
404,944,942
56
5, IT
69,752
168,889
213,142
513,888
282,894
682,777
54,013,069
131,455,303
57
5, LEIDY SE(FT)
225,878
168,588
1,406,572
1,167,445
1,632,450
1,336,033
211,599,883
221,490,249
58
5, MID-SOUTH(FT)
40,244
45,395
33,322,720
33,403,927
33,362,964
33,449,322
30,956,999
34,919,119
59
5, MOMENTUM(FT)
29,921
26,276
9,759,013
10,255,789
9,788,934
10,282,065
23,958,628
21,580,868
60
5, POTOMAC(FT)
20,649
25,909
2,537,003
2,579,090
2,557,652
2,604,999
21,426,360
27,900,400
61
5, SENTINEL(FT)
2,400
4,195
12,412
21,656
14,812
25,851
2,991,541
3,431,506
62
5, SUNBELT(FT)
32,906
23,602
14,456,002
14,381,784
14,488,908
14,405,386
25,549,754
18,251,231
63
5, SUNDANCE(FT)
35,698
34,616
9,887,476
10,019,454
9,923,174
10,054,070
27,493,411
26,630,780
64
5, VA SOUTHSIDE(FT)
109,761
115,441
43,682,605
46,328,789
43,792,366
46,444,230
124,167,513
143,952,630
65
5, VA S-SIDE 2(FT)
47,810
1,313
40,134,844
3,389,729
40,182,654
3,391,042
42,268,031
887,091
66
Subtotal Zone 5
1,580,334
1,238,485
408,153,609
351,563,028
409,733,943
352,801,513
1,429,389,968
1,255,179,466
67
6, ATL SUNRISE(FT)
36,945
10,570
28,740,965
73,688
28,777,910
84,258
51,701,175
10,517,821
68
6, DALTON(FT)
2,622
2,453
29,599
20,779
32,221
23,232
7,686,693
3,237,872
69
6, FDLS
121,825
114,392
85,598,385
87,330,091
85,720,210
87,444,483
93,845,776
87,993,114
70
6, FT
948,708
1,006,893
453,345,525
453,910,059
454,294,233
454,916,952
1,093,340,265
1,151,320,887
71
6, GARDEN STATE(FT)
10,055
1,327
19,546,607
845,077
19,556,662
846,404
8,255,934
1,020,841
72
6, IT
127,044
252,935
959,670
932,586
1,086,714
1,185,521
109,389,741
198,008,009
73
6, LEIDY EAST(FT)
42,316
47,336
15,251,203
15,101,027
15,293,519
15,148,363
66,175,981
72,233,186
74
6, LEIDY LI(FT)
16,457
15,758
14,002,648
14,687,023
14,019,105
14,702,781
18,318,992
19,201,536
75
6, LEIDY SE(FT)
26,629
40,970
177,062
274,029
203,691
314,999
69,290,993
133,737,048
76
6, MARKETLINK(FT)
87,776
93,974
31,290,622
32,035,554
31,378,399
32,129,528
142,772,099
176,799,001
77
6, MARKLINK-LLI(FT)
16,762
16,308
12,724,909
13,097,849
12,741,671
13,114,157
18,138,362
18,989,570
78
6, NE CONNECTOR(FT)
1,259
11,532
9,723,731
9,694,668
9,722,472
9,706,200
11,845,482
11,702,672
79
6, NESUPPLYLINK(FT)
88,291
85,375
54,346,438
54,257,415
54,434,730
54,342,790
133,480,683
135,708,610
80
6, NY Bay(FT)
659
304
22,833,815
5,538,768
22,834,473
5,539,072
2,654,713
233,900
81
6, POCONO(FT)
29,451
26,851
1,177,509
1,202,274
1,206,960
1,229,125
22,656,403
20,949,766
82
6, POTOMAC(FT)
2,154
4,425
7,758,542
7,777,541
7,760,695
7,781,966
5,395,716
5,230,743
83
6, ROCK SPRINGS(FT)
33,222
7,568
14,318,579
14,312,995
14,351,801
14,320,563
25,542,812
20,894,072
84
6, SENTINEL(FT)
44,921
46,488
32,328,865
32,374,794
32,373,785
32,421,282
57,269,905
60,792,829
85
6, TRENTON WB(FT)
7,926
9,649
1,297,529
1,330,597
1,305,456
1,340,246
6,099,299
7,421,282
86
6, VA SOUTHSIDE(FT)
6,084
12,679
20,044
12,381
26,128
25,060
5,125,071
11,424,362
87
6, VA S-SIDE 2(FT)
9,891
1,034
8,264
159
18,155
1,193
7,608,271
795,332
88
Subtotal Zone 6
1,658,479
1,808,821
805,480,511
744,809,354
807,138,990
746,618,175
1,956,594,366
2,148,212,453
89
Other
1,145,328
924,271
1,145,328
924,271
90
Total All Zones
5,109,502
4,524,790
1,764,180,046
1,530,914,030
1,769,289,548
1,535,438,820
(a)
5,525,098,298
(b)
5,139,205,113


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: QuantityOfNaturalGasRevenuesFromTransportationOfGasOfOthersThroughTransmissionFacilities

 

VOLUMES INCLUDE:

 

IT FEEDERS = 104,231,876 DEKATHERMS

FT FEEDERS = 1,123,071,589 DEKATHERMS

(b) Concept: QuantityOfNaturalGasRevenuesFromTransportationOfGasOfOthersThroughTransmissionFacilities

 

VOLUMES INCLUDE:

 

IT FEEDERS = 117,554,492 DEKATHERMS

FT FEEDERS = 1,255,023,435 DEKATHERMS


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Revenues from Storing Gas of Others (Account 489.4)
  1. Report revenues and Dth of gas withdrawn from storage by Rate Schedule and in total.
  2. Revenues for penalties including penalties for unauthorized overruns must be reported on page 308.
  3. Other revenues in columns (f) and (g) include reservation charges, deliverability charges, injection and withdrawal charges, less revenues reflected in columns (b) through (e).
  4. Dth of gas withdrawn from storage must not be adjusted for discounting.
  5. Where transportation services are bundled with storage services, report only Dth withdrawn from storage.
Line No.
ZoneOfDeliveryOrReceiptRateSchedule
Rate Schedule
(a)
RevenuesForTransitionCostsAndTakeOrPay
Revenues for Transition Costs and Take-or-Pay Amount for Current Year
(b)
RevenuesForTransitionCostsAndTakeOrPay
Revenues for Transaction Costs and Take-or-Pay Amount for Previous Year
(c)
RevenuesFromGRIAndACA
Revenues for GRI and ACA Amount for Current Year
(d)
RevenuesFromGRIAndACA
Revenues for GRI and ACA Amount for Previous Year
(e)
OtherRevenues
Other Revenues Amount for Current Year
(f)
OtherRevenues
Other Revenues Amount for Previous Year
(g)
RevenuesFromStoringGasOfOthers
Total Operating Revenues Amount for Current Year
(h)
RevenuesFromStoringGasOfOthers
Total Operating Revenues Amount for Previous Year
(i)
DekathermOfNaturalGas
Dekatherm of Natural Gas Amount for Current Year
(j)
DekathermOfNaturalGas
Dekatherm of Natural Gas Amount for Previous Year
(k)
1
EESWS
118,344
118,344
118,344
118,344
2
ESS
17,320,158
18,443,930
17,320,158
18,443,930
11,078,019
12,650,051
3
GSS
57,550,131
57,539,499
57,550,131
57,539,499
52,669,086
56,394,081
4
LG-A
1,173,346
1,190,735
1,173,346
1,190,735
257,883
554,309
5
LNG
9,215,643
9,184,147
9,215,643
9,184,147
6
LSS
11,815,413
11,569,598
11,815,413
11,569,598
11,439,424
10,507,814
7
S-2
8,278,754
8,411,093
8,278,754
8,411,093
9,829,636
9,382,622
8
SS-2
14,587,767
14,169,310
14,587,767
14,169,310
7,671,850
6,903,621
9
WSS
16,692,120
16,633,616
16,692,120
16,633,616
52,233,369
37,051,797
10
OTHER
85,258
89,657
85,258
89,657
11
TOTAL
136,666,418
137,349,929
136,666,418
137,349,929
145,179,267
133,444,295


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Other Gas Revenues (Account 495)

Report below transactions of $250,000 or more included in Account 495, Other Gas Revenues. Group all transactions below $250,000 in one amount and provide the number of items.

Line No.
Description of Transaction
(a)
Amount (in dollars)
(b)
1
CommissionsOnSaleOrDistributionOfGasOfOthers
Commissions on Sale or Distribution of Gas of Others
2
CompensationForMinorOrIncidentalServicesProvidedForOthers
Compensation for Minor or Incidental Services Provided for Others
3
ProfitOrLossOnSaleOfMaterialAndSuppliesNotOrdinarilyPurchasedForResale
Profit or Loss on Sale of Material and Supplies not Ordinarily Purchased for Resale
1,149,000
4
SalesOfStreamWaterOrElectricityIncludingSalesOrTransfersToOtherDepartments
Sales of Stream, Water, or Electricity, including Sales or Transfers to Other Departments
5
MiscellaneousRoyalties
Miscellaneous Royalties
6
RevenuesFromDehydrationAndOtherProcessingOfGasOfOthers
Revenues from Dehydration and Other Processing of Gas of Others except as provided for in the Instructions to Account 495
7
RevenuesForRightBenefitsReceivedFromOthersWhichAreRealizedThroughResearchDevelopmentAndDemonstrationVentures
Revenues for Right and/or Benefits Received from Others which are Realized Through Research, Development, and Demonstration Ventures
8
GainsOnSettlementsOfImbalanceReceivablesAndPayables
Gains on Settlements of Imbalance Receivables and Payables
35,287
9
RevenuesFromPenaltiesEarnedPursuantToTariffProvisionsIncludingPenaltiesAssociatedWithCashOutSettlements
Revenues from Penalties earned Pursuant to Tariff Provisions, including Penalties Associated with Cash-out Settlements
575,631
10
RevenuesFromShipperSuppliedGas
Revenues from Shipper Supplied Gas
11
Other revenues (Specify):
12
Other revenues (Specify):
13
Amt Rec Remit Tax
23,017
14
Cashout Sales
105,941,104
15
System Management Gas (SMG) Sales
10,521,504
16
Transportation of Liquids
2,004,624
40
TOTAL
116,800,905


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Discounted Rate Services and Negotiated Rate Services
  1. In column b, report the revenues from discounted rate services.
  2. In column c, report the volumes of discounted rate services.
  3. In column d, report the revenues from negotiated rate services.
  4. In column e, report the volumes of negotiated rate services.
Line No.
AccountDescription
Account
(a)
RevenueFromDiscountedRateServices
Discounted Rate Services Revenue
(b)
VolumesOfDiscountedRateServices
Discounted Rate Services Volumes
(c)
RevenuesFromNegotiatedRateServices
Negotiated Rate Services Revenue
(d)
VolumesOfNegotiatedRateServices
Negotiated Rate Services Volumes
(e)
1
Account 489.1, Revenues from transportation of gas of others through gathering facilities.
2
Account 489.2, Revenues from transportation of gas of others through transmission facilities.
26,532,691
163,417,963
804,350,824
67,112,094
3
Account 489.4, Revenues from storing gas of others.
231,545
5,818,574
4
Account 495, Other gas revenues.
12,485,093
4,610,435
40
Total
26,764,236
163,417,963
822,654,491
71,722,529


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Gas Operation and Maintenance Expenses
Line No.
Account
(a)
Amount for Current Year
(b)
Amount for Previous Year
(c)
1
ProductionExpensesAbstract
1. PRODUCTION EXPENSES
2
ManufacturedGasProductionAbstract
A. Manufactured Gas Production
3
ManufacturedGasProduction
Manufactured Gas Production (Submit Supplemental Statement)
4
NaturalGasProductionExpensesAbstract
B. Natural Gas Production
5
NaturalGasProductionAndGatheringPlantAbstract
B1. Natural Gas Production and Gathering
6
NaturalGasProductionAndGatheringOperationAbstract
Operation
7
OperationSupervisionAndEngineeringNaturalGasProductionAndGathering
750 Operation Supervision and Engineering
171,037
511,560
8
ProductionMapsAndRecords
751 Production Maps and Records
9
GasWellsExpenses
752 Gas Well Expenses
10
FieldLinesExpenses
753 Field Lines Expenses
1,288,021
1,975,200
11
FieldCompressorStationExpenses
754 Field Compressor Station Expenses
12
FieldCompressorStationFuelAndPower
755 Field Compressor Station Fuel and Power
13
FieldMeasuringAndRegulatingStationExpenses
756 Field Measuring and Regulating Station Expenses
34,919
794,354
14
PurificationExpensesNaturalGasProductionAndGathering
757 Purification Expenses
15
GasWellRoyalties
758 Gas Well Royalties
16
OtherExpensesNaturalGasProductionAndGathering
759 Other Expenses
822,067
1,190,226
17
RentsNaturalGasProductionAndGathering
760 Rents
5,123
18
ProductionOperationExpense
TOTAL Operation (Total of lines 7 thru 17)
2,321,167
4,471,340
19
NaturalGasProductionAndGatheringMaintenanceAbstract
Maintenance
20
MaintenanceSupervisionAndEngineeringNaturalGasProductionAndGathering
761 Maintenance Supervision and Engineering
6,983
1,086
21
MaintenanceOfStructuresAndImprovementsNaturalGasProductionAndGathering
762 Maintenance of Structures and Improvements
32,810
22,011
22
MaintenanceOfProducingGasWells
763 Maintenance of Producing Gas Wells
23
MaintenanceOfFieldLines
764 Maintenance of Field Lines
24
MaintenanceOfFieldCompressorStationEquipment
765 Maintenance of Field Compressor Station Equipment
25
MaintenanceOfFieldMeasuringAndRegulatingStationEquipment
766 Maintenance of Field Measuring and Regulating Station Equipment
15,308
102,084
26
MaintenanceOfPurificationEquipment
767 Maintenance of Purification Equipment
27
MaintenanceOfDrillingAndCleaningEquipment
768 Maintenance of Drilling and Cleaning Equipment
28
MaintenanceOfOtherEquipmentNaturalGasProductionAndGathering
769 Maintenance of Other Equipment
29
ProductionMaintenanceExpense
TOTAL Maintenance (Total of lines 20 thru 28)
55,101
125,181
30
ProductionOperationAndMaintenanceExpense
TOTAL Natural Gas Production and Gathering (Total of lines 18 and 29)
2,376,268
4,596,521
31
ProductsExtractionAbstract
B2. Products Extraction
32
NaturalGasProductionExtractionOperationAbstract
Operation
33
OperationSupervisionAndEngineeringProductsExtraction
770 Operation Supervision and Engineering
34
OperationLaborNaturalGasProduction
771 Operation Labor
35
GasShrinkage
772 Gas Shrinkage
36
Fuel
773 Fuel
37
Power
774 Power
38
Materials
775 Materials
39
OperationSuppliesAndExpenses
776 Operation Supplies and Expenses
40
GasProcessedByOthers
777 Gas Processed by Others
41
RoyaltiesOnProductsExtracted
778 Royalties on Products Extracted
42
MarketingExpenses
779 Marketing Expenses
43
ProductsPurchasedForResale
780 Products Purchased for Resale
44
VariationInProductsInventory
781 Variation in Products Inventory
45
ExtractedProductsUsedByTheUtilityCredit
(Less) 782 Extracted Products Used by the Utility-Credit
46
RentsProductsExtraction
783 Rents
47
ProductsExtractionOperationExpense
TOTAL Operation (Total of lines 33 thru 46)
48
NaturalGasProductionExtractionMaintenanceAbstract
Maintenance
49
MaintenanceSupervisionAndEngineeringProductsExtraction
784 Maintenance Supervision and Engineering
50
MaintenanceOfStructuresAndImprovementsProductsExtraction
785 Maintenance of Structures and Improvements
51
MaintenanceOfExtractionAndRefiningEquipment
786 Maintenance of Extraction and Refining Equipment
52
MaintenanceOfPipeLines
787 Maintenance of Pipe Lines
53
MaintenanceOfExtractedProductsStorageEquipment
788 Maintenance of Extracted Products Storage Equipment
54
MaintenanceOfCompressorEquipment
789 Maintenance of Compressor Equipment
55
MaintenanceOfGasMeasuringAndRegulatingEquipment
790 Maintenance of Gas Measuring and Regulating Equipment
56
MaintenanceOfOtherEquipmentProductsExtraction
791 Maintenance of Other Equipment
57
ProductsExtractionMaintenanceExpense
TOTAL Maintenance (Total of lines 49 thru 56)
58
ProductsExtractionExpense
TOTAL Products Extraction (Total of lines 47 and 57)
59
ExplorationAndDevelopmentExpensesAbstract
C. Exploration and Development
60
ExplorationAndDevelopmentOperationAbstract
Operation
61
DelayRentals
795 Delay Rentals
62
NonproductiveWellDrilling
796 Nonproductive Well Drilling
63
AbandonedLeases
797 Abandoned Leases
64
OtherExploration
798 Other Exploration
65
ExplorationAndDevelopmentOperatingExpense
TOTAL Exploration and Development (Total of lines 61 thru 64)
66
OtherGasSupplyExpensesAbstract
D. Other Gas Supply Expenses
67
OtherGasSupplyExpensesOperationAbstract
Operation
68
NaturalGasWellHeadPurchases
800 Natural Gas Well Head Purchases
69
NaturalGasWellHeadPurchasesIntracompanyTransfers
800.1 Natural Gas Well Head Purchases, Intracompany Transfers
70
NaturalGasFieldLinePurchases
801 Natural Gas Field Line Purchases
71
NaturalGasGasolinePlantOutletPurchases
802 Natural Gas Gasoline Plant Outlet Purchases
72
NaturalGasTransmissionLinePurchases
803 Natural Gas Transmission Line Purchases
187,614,188
112,839,485
73
NaturalGasCityGatePurchases
804 Natural Gas City Gate Purchases
74
LiquefiedNaturalGasPurchases
804.1 Liquefied Natural Gas Purchases
75
OtherGasPurchases
805 Other Gas Purchases
76
PurchasedGasCostAdjustments
(Less) 805.1 Purchases Gas Cost Adjustments
77
PurchasedGasOperationExpenses
TOTAL Purchased Gas (Total of lines 68 thru 76)
187,614,188
112,839,485
78
ExchangeGas
806 Exchange Gas
300,624
871,399
79
PurchasedGasExpensesAbstract
Purchased Gas Expenses
80
WellExpensePurchasedGas
807.1 Well Expense-Purchased Gas
81
OperationOfPurchasedGasMeasuringStations
807.2 Operation of Purchased Gas Measuring Stations
82
MaintenanceOfPurchasedGasMeasuringStations
807.3 Maintenance of Purchased Gas Measuring Stations
83
PurchasedGasCalculationsExpenses
807.4 Purchased Gas Calculations Expenses
84
OtherPurchasedGasExpenses
807.5 Other Purchased Gas Expenses
85
PurchasedGasExpenses
TOTAL Purchased Gas Expenses (Total of lines 80 thru 84)
86
GasWithdrawnFromStorageDebt
808.1 Gas Withdrawn from Storage-Debit
3,514,891
51,128,668
87
GasDeliveredToStorageCredit
(Less) 808.2 Gas Delivered to Storage-Credit
35,192,307
51,855,771
88
WithdrawalsOfLiquefiedNaturalGasHeldForProcessingDebit
809.1 Withdrawals of Liquefied Natural Gas for Processing-Debit
89
DeliveriesOfNaturalGasForProcessingCredit
(Less) 809.2 Deliveries of Natural Gas for Processing-Credit
90
GasUsedInUtilityOperationAbstract
Gas used in Utility Operation-Credit
91
GasUsedForCompressorStationFuelCredit
810 Gas Used for Compressor Station Fuel-Credit
(a)
36,090,325
22,366,324
92
GasUsedForProductsExtractionCredit
811 Gas Used for Products Extraction-Credit
93
GasUsedForOtherUtilityOperationsCredit
812 Gas Used for Other Utility Operations-Credit
49,213,410
34,311,948
94
GasUsedInUtilityOperationCredit
TOTAL Gas Used in Utility Operations-Credit (Total of lines 91 thru 93)
13,123,085
11,945,624
95
OtherGasSupplyExpenses
813 Other Gas Supply Expenses
42,173,746
27,854,221
96
OtherGasSupplyExpensesOperation
TOTAL Other Gas Supply Exp. (Total of lines 77,78,85,86 thru 89,94,95)
178,258,275
128,892,378
97
ProductionExpenses
TOTAL Production Expenses (Total of lines 3, 30, 58, 65, and 96)
180,634,543
133,488,899
98
NaturalGasStorageTerminalingAndProcessingExpensesAbstract
2. NATURAL GAS STORAGE, TERMINALING AND PROCESSING EXPENSES
99
UndergroundStorageExpensesAbstract
A. Underground Storage Expenses
100
UndergroundStorageEpensesOperationAbstract
Operation
101
OperationSupervisionAndEngineeringUndergroundStorageExpenses
814 Operation Supervision and Engineering
1,878,919
549,857
102
MapsAndRecords
815 Maps and Records
103
WellsExpenses
816 Wells Expenses
1,953,271
1,084,638
104
LinesExpenses
817 Lines Expense
424,214
233,192
105
CompressorStationExpenses
818 Compressor Station Expenses
6,523,167
4,989,603
106
CompressorStationFuelAndPowerUndergroundStorageExpenses
819 Compressor Station Fuel and Power
8,116,818
6,369,041
107
MeasuringAndRegulatingStationExpenses
820 Measuring and Regulating Station Expenses
301,023
104,579
108
PurificationExpensesUndergroundStorage
821 Purification Expenses
60,975
142,853
109
ExplorationAndDevelopment
822 Exploration and Development
110
GasLossesUndergroundStorageExpenses
823 Gas Losses
497,046
692,273
111
OtherExpensesUndergroundStorage
824 Other Expenses
57,211,153
55,932,393
112
StorageWellRoyalties
825 Storage Well Royalties
6,219
313,469
113
RentsUndergroundStorageExpenses
826 Rents
1,514,945
10,398
114
UndergroundStorageOperationExpenses
TOTAL Operation (Total of lines of 101 thru 113)
77,371,708
70,422,296
115
UndergroundStorageEpensesMaintenanceAbstract
Maintenance
116
MaintenanceSupervisionAndEngineeringUndergroundStorageExpenses
830 Maintenance Supervision and Engineering
18,732
15,428
117
MaintenanceOfStructuresAndImprovementsUndergroundStorageExpenses
831 Maintenance of Structures and Improvements
330,867
190,777
118
MaintenanceOfReservoirsAndWells
832 Maintenance of Reservoirs and Wells
975,000
870,921
119
MaintenanceOfLines
833 Maintenance of Lines
197,514
623,035
120
MaintenanceOfCompressorStationEquipmentUndergroundStorageExpenses
834 Maintenance of Compressor Station Equipment
8,777,590
4,740,165
121
MaintenanceOfMeasuringAndRegulatingStationEquipmentUndergroundStorageExpenses
835 Maintenance of Measuring and Regulating Station Equipment
13,750
6,347
122
MaintenanceOfPurificationEquipmentUndergroundStorageExpenses
836 Maintenance of Purification Equipment
1,162,254
720,931
123
MaintenanceOfOtherEquipmentUndergroundStorageExpenses
837 Maintenance of Other Equipment
515,051
322,300
124
UndergroundStorageMaintenanceExpenses
TOTAL Maintenance (Total of lines 116 thru 123)
11,990,758
7,489,904
125
UndergroundStorageExpenses
TOTAL Underground Storage Expenses (Total of lines 114 and 124)
89,362,466
77,912,200
126
OtherStorageExpensesAbstract
B. Other Storage Expenses
127
OtherStorageExpensesOperationAbstract
Operation
128
OperationSupervisionAndEngineeringOtherStorageExpenses
840 Operation Supervision and Engineering
18,740
4,876
129
OperationLaborAndExpenses
841 Operation Labor and Expenses
4,057,371
4,050,839
130
RentsOtherStorageExpenses
842 Rents
131
FuelOtherStorageExpenses
842.1 Fuel
579,497
560,026
132
PowerOtherStorageExpenses
842.2 Power
105,305
133
GasLossesOtherStorageExpenses
842.3 Gas Losses
134
OtherStorageOperationExpenses
TOTAL Operation (Total of lines 128 thru 133)
4,760,913
4,615,741
135
OtherStorageExpensesMaintenanceAbstract
Maintenance
136
MaintenanceSupervisionAndEngineeringOtherStorageExpenses
843.1 Maintenance Supervision and Engineering
53
137
MaintenanceOfStructuresAndImprovementsOtherStorageExpenses
843.2 Maintenance of Structures
138
MaintenanceOfGasHolders
843.3 Maintenance of Gas Holders
139
MaintenanceOfPurificationEquipmentOtherStorageExpenses
843.4 Maintenance of Purification Equipment
140
MaintenanceOfLiquefactionEquipmentOtherStorageExpenses
843.5 Maintenance of Liquefaction Equipment
141
MaintenanceOfVaporizingEquipmentOtherStorageExpenses
843.6 Maintenance of Vaporizing Equipment
421
12,907
142
MaintenanceOfCompressorEquipmentOtherStorageExpenses
843.7 Maintenance of Compressor Equipment
73,859
11,267
143
MaintenanceOfMeasuringAndRegulatingEquipmentOtherStorageExpenses
843.8 Maintenance of Measuring and Regulating Equipment
1,782
6,701
144
MaintenanceOfOtherEquipmentOtherStorageExpenses
843.9 Maintenance of Other Equipment
102,079
42,800
145
OtherStorageMaintenanceExpenses
TOTAL Maintenance (Total of lines 136 thru 144)
177,352
73,675
146
OtherStorageExpenses
TOTAL Other Storage Expenses (Total of lines 134 and 145)
4,938,265
4,689,416
147
LiquifiedNaturalGasTerminalingAndProcessingExpensesAbstract
C. Liquefied Natural Gas Terminaling and Processing Expenses
148
LiquefiedNaturalGasTerminalingAndProcessingExpensesOperationAbstract
Operation
149
OperationSupervisionAndEngineeringLiquefiedNaturalGasTerminalingAndProcessingExpenses
844.1 Operation Supervision and Engineering
150
LngProcessingTerminalLaborAndExpenses
844.2 LNG Processing Terminal Labor and Expenses
151
LiquefactionProcessingLaborAndExpenses
844.3 Liquefaction Processing Labor and Expenses
152
LngTransportationLaborAndExpenses
844.4 Liquefaction Transportation Labor and Expenses
153
MeasuringAndRegulatingLaborAndExpenses
844.5 Measuring and Regulating Labor and Expenses
154
CompressorStationLaborAndExpensesLiquefiedNaturalGasTerminalingAndProcessingExpenses
844.6 Compressor Station Labor and Expenses
155
CommunicationSystemExpensesLiquefiedNaturalGasTerminalingAndProcessingExpenses
844.7 Communication System Expenses
156
SystemControlAndLoadDispatchingLiquefiedNaturalGasTerminalingAndProcessingExpenses
844.8 System Control and Load Dispatching
157
FuelLiquefiedNaturalGasTerminalingAndProcessingExpenses
845.1 Fuel
158
PowerLiquefiedNaturalGasTerminalingAndProcessingExpenses
845.2 Power
159
RentsLiquefiedNaturalGasTerminalingAndProcessing
845.3 Rents
160
DemurrageChargesLiquefiedNaturalGasTerminalingAndProcessingExpenses
845.4 Demurrage Charges
161
WharfageReceiptsCreditLiquefiedNaturalGasTerminalingAndProcessingExpenses
(less) 845.5 Wharfage Receipts-Credit
162
ProcessingLiquefiedOrVaporizedGasByOthers
845.6 Processing Liquefied or Vaporized Gas by Others
163
GasLossesLiquefiedNaturalGasTerminalingAndProcessingExpenses
846.1 Gas Losses
164
OtherExpensesLiquefiedNaturalGasTerminalingAndProcessing
846.2 Other Expenses
165
LiquifiedNaturalGasTerminalingAndProcessingOperationExpenses
TOTAL Operation (Total of lines 149 thru 164)
166
LiquefiedNaturalGasTerminalingAndProcessingExpensesMaintenanceAbstract
Maintenance
167
MaintenanceSupervisionAndEngineeringLiquefiedNaturalGasTerminalingAndProcessingExpenses
847.1 Maintenance Supervision and Engineering
168
MaintenanceOfStructuresAndImprovementsLiquefiedNaturalGasTerminalingAndProcessingExpenses
847.2 Maintenance of Structures and Improvements
169
MaintenanceOfLngProcessingTerminalEquipment
847.3 Maintenance of LNG Processing Terminal Equipment
170
MaintenanceOfLngTransportationEquipment
847.4 Maintenance of LNG Transportation Equipment
171
MaintenanceOfMeasuringAndRegulatingEquipment
847.5 Maintenance of Measuring and Regulating Equipment
172
MaintenanceOfCompressorStationEquipmentLiquefiedNaturalGasTerminalingAndProcessingExpenses
847.6 Maintenance of Compressor Station Equipment
173
MaintenanceOfCommunicationEquipmentLiquefiedNaturalGasTerminalingAndProcessingExpenses
847.7 Maintenance of Communication Equipment
174
MaintenanceOfOtherEquipmentLiquefiedNaturalGasTerminalingAndProcessingExpenses
847.8 Maintenance of Other Equipment
175
LiquifiedNaturalGasTerminalingAndProcessingMaintenanceExpenses
TOTAL Maintenance (Total of lines 167 thru 174)
176
LiquifiedNaturalGasTerminalingAndProcessingExpenses
TOTAL Liquefied Nat Gas Terminaling and Proc Exp (Total of lines 165 and 175)
177
NaturalGasStorageExpense
TOTAL Natural Gas Storage (Total of lines 125, 146, and 176)
94,300,731
82,601,616
178
TransmissionExpensesAbstract
3. TRANSMISSION EXPENSES
179
TransmissionExpensesOperationAbstract
Operation
180
OperationSupervisionAndEngineeringGasTransmissionExpenses
850 Operation Supervision and Engineering
43,465,478
71,468,406
181
SystemControlAndLoadDispatchingGas
851 System Control and Load Dispatching
3,874,302
3,489,828
182
CommunicationSystemExpenses
852 Communication System Expenses
4,595,920
5,587,291
183
CompressorStationLaborAndExpensesTransmissionExpenses
853 Compressor Station Labor and Expenses
58,438,158
52,596,302
184
GasForCompressorStationFuel
854 Gas for Compressor Station Fuel
45,496,379
28,385,734
185
OtherFuelAndPowerForCompressorStations
855 Other Fuel and Power for Compressor Stations
40,411,214
25,121,324
186
MainsExpenses
856 Mains Expenses
111,949,156
126,823,955
187
MeasuringAndRegulatingStationExpensesTransmissionExpenses
857 Measuring and Regulating Station Expenses
4,070,138
4,191,949
188
TransmissionAndCompressionOfGasByOthers
858 Transmission and Compression of Gas by Others
189
OtherExpensesGasTransmission
859 Other Expenses
7,136,232
3,543,559
190
RentsGasTransmissionExpense
860 Rents
6,496,454
3,825,801
191
TransmissionOperationExpense
TOTAL Operation (Total of lines 180 thru 190)
234,940,673
268,262,681
192
TransmissionExpensesMaintenanceAbstract
Maintenance
193
MaintenanceSupervisionAndEngineeringGasTransmissionExpenses
861 Maintenance Supervision and Engineering
342,071
809,482
194
MaintenanceOfStructuresAndImprovementsTransmissionExpenses
862 Maintenance of Structures and Improvements
7,231,761
5,731,880
195
MaintenanceOfMainsTransmissionExpenses
863 Maintenance of Mains
5,318,263
3,845,653
196
MaintenanceOfCompressorStationEquipmentTransmissionExpenses
864 Maintenance of Compressor Station Equipment
34,850,377
15,036,312
197
MaintenanceOfMeasuringAndRegulatingStationEquipment
865 Maintenance of Measuring and Regulating Station Equipment
1,412,602
973,798
198
MaintenanceOfCommunicationEquipmentGasTransmission
866 Maintenance of Communication Equipment
245,338
73,446
199
MaintenanceOfOtherEquipmentTransmissionExpenses
867 Maintenance of Other Equipment
2,066,431
82,403
200
TransmissionMaintenanceExpensesGas
TOTAL Maintenance (Total of lines 193 thru 199)
51,466,843
26,552,974
201
TransmissionExpenses
TOTAL Transmission Expenses (Total of lines 191 and 200)
286,407,516
294,815,655
202
DistributionExpensesAbstract
4. DISTRIBUTION EXPENSES
203
DistributionExpensesOperationAbstract
Operation
204
OperationSupervisionAndEngineeringDistributionExpenses
870 Operation Supervision and Engineering
205
DistributionLoadDispatching
871 Distribution Load Dispatching
206
CompressorStationLaborAndExpenses
872 Compressor Station Labor and Expenses
207
CompressorStationFuelAndPowerDistributionExpenses
873 Compressor Station Fuel and Power
208
MainsAndServicesExpenses
874 Mains and Services Expenses
209
MeasuringAndRegulatingStationExpensesGeneral
875 Measuring and Regulating Station Expenses-General
210
MeasuringAndRegulatingStationExpensesIndustrial
876 Measuring and Regulating Station Expenses-Industrial
211
MeasuringAndRegulatingStationExpensesCityGateCheckStations
877 Measuring and Regulating Station Expenses-City Gas Check Station
212
MeterAndHouseRegulatorExpenses
878 Meter and House Regulator Expenses
213
CustomerInstallationsExpenses
879 Customer Installations Expenses
214
OtherExpensesGasDistribution
880 Other Expenses
215
RentsDistributionExpense
881 Rents
216
DistributionOperationExpensesGas
TOTAL Operation (Total of lines 204 thru 215)
217
DistributionExpensesMaintenanceAbstract
Maintenance
218
MaintenanceSupervisionAndEngineeringDistributionExpenses
885 Maintenance Supervision and Engineering
219
MaintenanceOfStructuresAndImprovementsDistributionExpenses
886 Maintenance of Structures and Improvements
220
MaintenanceOfMains
887 Maintenance of Mains
221
MaintenanceOfCompressorStationEquipment
888 Maintenance of Compressor Station Equipment
222
MaintenanceOfMeasuringAndRegulatingStationEquipmentGeneral
889 Maintenance of Measuring and Regulating Station Equipment-General
223
MaintenanceOfMeasuringAndRegulatingStationEquipmentIndustrial
890 Maintenance of Meas. and Reg. Station Equipment-Industrial
224
MaintenanceOfMeasuringAndRegulatingStationEquipmentCityGateCheckStations
891 Maintenance of Meas. and Reg. Station Equip-City Gate Check Station
225
MaintenanceOfServices
892 Maintenance of Services
226
MaintenanceOfMetersAndHouseRegulators
893 Maintenance of Meters and House Regulators
227
MaintenanceOfOtherEquipmentGasDistribution
894 Maintenance of Other Equipment
228
DistributionMaintenanceExpenseGas
TOTAL Maintenance (Total of lines 218 thru 227)
229
DistributionExpenses
TOTAL Distribution Expenses (Total of lines 216 and 228)
230
CustomerAccountsExpensesAbstract
5. CUSTOMER ACCOUNTS EXPENSES
231
CustomerAccountsExpensesOperationsAbstract
Operation
232
SupervisionCustomerAccountExpenses
901 Supervision
233
MeterReadingExpenses
902 Meter Reading Expenses
234
CustomerRecordsAndCollectionExpenses
903 Customer Records and Collection Expenses
235
UncollectibleAccounts
904 Uncollectible Accounts
7,941
236
MiscellaneousCustomerAccountsExpenses
905 Miscellaneous Customer Accounts Expenses
237
CustomerAccountExpenses
TOTAL Customer Accounts Expenses (Total of lines 232 thru 236)
7,941
238
CustomerServiceAndInformationalExpensesAbstract
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
239
CustomerServiceAndInformationalExpensesOperationAbstract
Operation
240
SupervisionCustomerServiceAndInformationExpenses
907 Supervision
241
CustomerAssistanceExpenses
908 Customer Assistance Expenses
242
InformationalAndInstructionalAdvertisingExpenses
909 Informational and Instructional Expenses
243
MiscellaneousCustomerServiceAndInformationalExpenses
910 Miscellaneous Customer Service and Informational Expenses
244
CustomerServiceAndInformationalExpenses
TOTAL Customer Service and Information Expenses (Total of lines 240 thru 243)
245
SalesExpensesAbstract
7. SALES EXPENSES
246
SalesExpenseOperationAbstract
Operation
247
SupervisionSalesExpense
911 Supervision
248
DemonstratingAndSellingExpenses
912 Demonstrating and Selling Expenses
249
AdvertisingExpenses
913 Advertising Expenses
250
MiscellaneousSalesExpenses
916 Miscellaneous Sales Expenses
251
SalesExpenses
TOTAL Sales Expenses (Total of lines 247 thru 250)
252
AdministrativeAndGeneralExpensesAbstract
8. ADMINISTRATIVE AND GENERAL EXPENSES
253
AdministrativeAndGeneralExpensesOperationAbstract
Operation
254
AdministrativeAndGeneralSalaries
920 Administrative and General Salaries
38,537,875
36,422,830
255
OfficeSuppliesAndExpenses
921 Office Supplies and Expenses
2,287,053
4,120,752
256
AdministrativeExpensesTransferredCredit
(Less) 922 Administrative Expenses Transferred-Credit
6,557,451
6,179,355
257
OutsideServicesEmployed
923 Outside Services Employed
52,455,964
52,032,283
258
PropertyInsurance
924 Property Insurance
11,969,152
12,912,007
259
InjuriesAndDamages
925 Injuries and Damages
3,877,246
2,754,626
260
EmployeePensionsAndBenefits
926 Employee Pensions and Benefits
21,158,415
23,746,624
261
FranchiseRequirements
927 Franchise Requirements
262
RegulatoryCommissionExpenses
928 Regulatory Commission Expenses
4,914,993
4,298,976
263
DuplicateChargesCredit
(Less) 929 Duplicate Charges-Credit
264
GeneralAdvertisingExpenses
930.1General Advertising Expenses
265
MiscellaneousGeneralExpenses
930.2Miscellaneous General Expenses
65,148,133
58,588,106
266
RentsAdministrativeAndGeneralExpense
931 Rents
5,564,093
5,600,452
267
AdministrativeAndGeneralOperationExpense
TOTAL Operation (Total of lines 254 thru 266)
199,355,473
194,297,301
268
MaintenanceAbstract
Maintenance
269
MaintenanceOfGeneralPlant
932 Maintenance of General Plant
270
AdministrativeAndGeneralExpenses
TOTAL Administrative and General Expenses (Total of lines 267 and 269)
199,355,473
194,297,301
271
OperationsAndMaintenanceExpensesGas
TOTAL Gas O&M Expenses (Total of lines 97,177,201,229,237,244,251, and 270)
760,706,204
705,203,471


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: GasUsedForCompressorStationFuelCredit
Duplicate fact discrepancy. Schedule: 331 - Schedule - Gas Used in Utility Operations, Row: 1, Column: d, Value: 94956463

Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Exchange and Imbalance Transactions
  1. Report below details by zone and rate schedule concerning the gas quantities and related dollar amount of imbalances associated with system balancing and no-notice service. Also, report certificated natural gas exchange transactions during the year. Provide subtotals for imbalance and no-notice quantities for exchanges. If respondent does not have separate zones, provide totals by rate schedule. Minor exchange transactions (less than 100,000 Dth) may be grouped.
Line No.
DescriptionOfZoneAndRateSchedule
Zone/Rate Schedule
(a)
NaturalGasReceivedByRespondentExchangedGasReceivedFromOthers
Gas Received from Others Amount
(b)
QuantityOfNaturalGasReceivedByUtilityExchangedGasReceivedFromOthers
Gas Received from Others Dth
(c)
NaturalGasDeliveredByRespondentExchangeGasDeliveredToOthers
Gas Delivered to Others Amount
(d)
QuantityOfNaturalGasDeliveredByUtilityExchangeGasDeliveredToOthers
Gas Delivered to Others Dth
(e)
1
Exhange
2
Zone 1
3
Zone 2
4
Zone 3
5
Zone 4
6
Zone 5
7
Zone 6
28,951,865
8,781,337
28,951,865
8,781,337
8
Other
9
Subtotal Exchange
28,951,865
8,781,337
28,951,865
8,781,337
10
Non-Exchange
11
Zone 1
8,486,338
2,492,088
8,362,190
2,457,668
12
Zone 2
78,696,366
23,115,507
78,075,402
22,958,724
13
Zone 3
7,728,891
2,258,933
7,243,568
2,121,637
14
Zone 4
2,771,747
806,082
2,217,682
655,682
15
Zone 5
9,114,209
2,594,584
7,280,172
2,200,408
16
Zone 6
3,970,079
1,197,835
3,753,209
1,063,246
17
Zone 7
9,751
2,171
1,059
2,180
18
Other
19
Subtotal Non-Exchange
110,777,381
32,467,200
106,931,164
31,455,185
20
Other
724,052
28,324
21
Adjustment to Recorded Estimate
4,269,645
25
Total
136,183,653
41,220,213
135,883,029
40,236,522


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Gas Used in Utility Operations
  1. Report below details of credits during the year to Accounts 810, 811, and 812.
  2. If any natural gas was used by the respondent for which a charge was not made to the appropriate operating expense or other account, list separately in column (c) the Dth of gas used, omitting entries in column (d).
Line No.
Purpose for Which Gas Was Used
(a)
Account Charged
(b)
Natural Gas Gas Used Dth
(c)
Natural Gas Amount of Credit (in dollars)
(d)
1
810 Gas Used for Compressor Station Fuel - Credit
29,516,938
(a)
36,090,325
2
811 Gas Used for Products Extraction - Credit
3
Gas Shrinkage and Other Usage in Respondent's Own Processing - Credit
4
Gas Shrinkage, etc. for Respondent's Gas Processed by Others - Credit
5
812 Gas Used for Other Utility Operations - Credit (Report separately for each principal use. Group minor uses.)
6
812 PURGING
(b)
1,388,427
(c)
3,855,391
7
812 LINE PACK
1,408,188
2,562,443
8
LNG FACILITY-SHRINKAGE
185,512
579,497
9
LNG FACILITY-SHRINKAGE
10
PURIFICATION FUEL
11
PURIFICATION EXPENSES-PIPELINE
12
810 STORAGE COMPRESSOR FUEL
2,756,865
8,406,054
13
810 MISC-FUEL USE RESP
45,969,578
139,452,842
14
812 DEHYDRATION FUEL
12,784
39,718
15
812 GAS LOSSES & UNACCOUNTED FOR
13,561,628
42,176,361
25
Total
2,860,764
13,123,085


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: GasUsedForCompressorStationFuelCredit
Duplicate fact discrepancy. Schedule: 331 - Schedule - Gas Used in Utility Operations, Row: 1, Column: d, Value: 94956463
(b) Concept: QuantityOfNaturalGasDeliveredByRespondentGasUsedForOtherUtilityOperations

 

PURGING – ACCOUNTS CHARGED

 

ACCOUNT DT’S

 

10701001 1,122,697

10898001 0

18608001 269

85600001 265.461

1,388,427

(c) Concept: GasUsedForOtherUtilityOperationsCredit

 

PURGING – ACCOUNTS CHARGED

 

ACCOUNT DOLLARS

 

10701001 $3,052,012

10898001 0

18608001 810

85600001 802,569

$3,855,391


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Transmission and Compression of Gas by Others (Account 858)
  1. Report below details concerning gas transported or compressed for respondent by others equalling more than 1,000,000 Dth and amounts of payments for such services during the year. Minor items (less than 1,000,000) Dth may be grouped. Also, include in column (c) amounts paid as transition costs to an upstream pipeline.
  2. In column (a) give name of companies, points of delivery and receipt of gas. Designate points of delivery and receipt so that they can be identified readily on a map of respondent's pipeline system.
  3. Designate associated companies with an asterisk in column (b).
Line No.
DescriptionOfNameOfCompanyAndServicePerformed
Name of Company and Description of Service Performed
(a)
IndicationOfAssociatedCompany
*
(b)
TransmissionAndCompressionOfGasByOthers
Amount of Payment
(c)
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasToOthersForTransportation
Dth of Gas Delivered
(d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Total


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Other Gas Supply Expenses (Account 813)
  1. Report other gas supply expenses by descriptive titles that clearly indicate the nature of such expenses. Show maintenance expenses, revaluation of monthly encroachments recorded in Account 117.4, and losses on settlements of imbalances and gas losses not associated with storage separately. Indicate the functional classification and purpose of property to which any expenses relate. List separately items of $250,000 or more.
Line No.
DescriptionOfOtherGasSupplyExpenses
Description
(a)
OtherGasSupplyExpenses
Amount (in dollars)
(b)
1
LOST AND UNACCOUNTED FOR
42,173,746
25
Total
42,173,746


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Miscellaneous General Expenses (Account 930.2)
  1. Provide the information requested below on miscellaneous general expenses.
  2. For Other Expenses, show the (a) purpose, (b) recipient and (c) amount of such items. List separately amounts of $250,000 or more however, amounts less than $250,000 may be grouped if the number of items of so grouped is shown.
Line No.
Description
(a)
Amount
(b)
1
ferc:IndustryAssociationDues
Industry association dues.
5,000
2
ferc:ExperimentalAndGeneralResearchExpensesAbstract
Experimental and general research expenses
2a
ferc:GasResearchInstituteExpense
a. Gas Research Institute (GRI)
2b
ferc:OtherExperimentalAndGeneralResearchExpenses
b. Other
3
ferc:PublicationAndDistributionExpensesForSecuritiesToStockholders
Publishing and distributing information and reports to stockholders, trustee, registrar, and transfer agent fees and expenses, and other expenses of servicing outstanding securities of the respondent
4
Other expenses
5
The Williams Companies, Inc Overheads
63,426,352
6
WPZ Overhead
1,712,719
7
WPO Overhead
4,062
25
TOTAL
65,148,133


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
Depreciation, Depletion and Amortization of Gas Plant (Accts 403, 404.1, 404.2, 404.3, 405) (Except Amortization of Acquisition Adjustments)
  1. Report in Section A the amounts of depreciation expense, depletion and amortization for the accounts indicated and classified according to the plant functional groups shown.
  2. Report in Section B, column (b) all depreciable or amortizable plant balances to which rates are applied and show a composite total. (If more desirable, report by plant account, subaccount or functional classifications other than those pre-printed in column (a). Indicate in a footnote the manner in which column (b) balances are obtained. If average balances are used, state the method of averaging used. For column (c) report available information for each plant functional classification listed in column (a). If composite depreciation accounting is used, report available information called for in columns (b) and (c) on this basis. Where the unit-of-production method is used to determine depreciation charges, show in a footnote any revisions made to estimated gas reserves.
  3. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state in a footnote the amounts and nature of the provisions and the plant items to which related.
  4. Add rows as necessary to completely report all data. Number the additional rows in sequence as 2.01, 2.02, 3.01, 3.02, etc.
Section A. Summary of Depreciation, Depletion, and Amortization Charges
Line No.
FunctionalClassificationAxis
Functional Classification
(a)
DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments
Depreciation Expense (Account 403)
(b)
DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments
Amortization Expense for Asset Retirement Costs (Account 403.1)
(c)
AmortizationAndDepletionOfProducingNaturalGasLandAndLandRights
Amortization and Depletion of Producing Natural Gas Land and Land Rights (Account 404.1)
(d)
AmortizationOfUndergroundStorageLandAndLandRights
Amortization of Underground Storage Land and Land Rights (Account 404.2)
(e)
AmortizationOfOtherLimitedTermGasPlant
Amortization of Other Limited-term Gas Plant (Account 404.3)
(f)
AmortizationOfOtherGasPlant
Amortization of Other Gas Plant (Account 405)
(g)
DepreciationDepletionAndAmortizationCharges
Total (b to g)
(h)
1
Intangible plant
1,026,583
1,026,583
2
Production plant, manufactured gas
3
Production and Gathering Plant
1,994,722
710,605
2,705,327
4
Products extraction plant
5
Underground Gas Storage Plant (footnote details)
7,713,637
2,658,896
10,372,533
6
Other storage plant
1,609,641
1,609,641
7
Base load LNG terminaling and processing plant
8
Transmission Plant
308,242,656
11,114,325
297,128,331
9
Distribution plant
10
General Plant (footnote details)
9,416,942
4,078,461
13,495,403
11
Common plant-gas
12
Total
328,977,598
7,744,824
4,078,461
1,026,583
326,337,818


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
Depreciation, Depletion and Amortization of Gas Plant (Accts 403, 404.1, 404.2, 404.3, 405) (Except Amortization of Acquisition Adjustments)
  1. Report in Section A the amounts of depreciation expense, depletion and amortization for the accounts indicated and classified according to the plant functional groups shown.
  2. Report in Section B, column (b) all depreciable or amortizable plant balances to which rates are applied and show a composite total. (If more desirable, report by plant account, subaccount or functional classifications other than those pre-printed in column (a). Indicate in a footnote the manner in which column (b) balances are obtained. If average balances are used, state the method of averaging used. For column (c) report available information for each plant functional classification listed in column (a). If composite depreciation accounting is used, report available information called for in columns (b) and (c) on this basis. Where the unit-of-production method is used to determine depreciation charges, show in a footnote any revisions made to estimated gas reserves.
  3. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state in a footnote the amounts and nature of the provisions and the plant items to which related.
  4. Add rows as necessary to completely report all data. Number the additional rows in sequence as 2.01, 2.02, 3.01, 3.02, etc.
Section B. Factors Used in Estimating Depreciation Charges
Line No.
FunctionalLocationClassificationAxis
Functional Classification
(a)
PlantBasesUsedInEstimatingDepreciationCharges
Plant Bases (in thousands)
(b)
AppliedDepreciationOrAmortizationRates
Applied Depreciation or Amortization Rates (percent)
(c)
1
Production and Gathering Plant
2
Offshore (footnote details)
3
Onshore (footnote details)
4
Underground Gas Storage Plant (footnote details)
5
Transmission Plant
6
Offshore (footnote details)
7
Onshore (footnote details)
8
General Plant (footnote details)
9


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionOfItemizedFunctionalClassification

 

AT 12/31/2018, DEPRECIATION WAS COMPUTED AT THE FOLLOWING RATES

 

INTANGIBLE PLANT 1.88% PER ANNUM

PRODUCTION AND GATHERING PLANT

ONSHORE 2.50% PER ANNUM

OFFSHORE 1.35% PER ANNUM

 

UNDERGROUND STORAGE PLANT 2.10% PER ANNUM

OTHER STORAGE-LNG PLANT 2.10% PER ANNUM

OTHER STORAGE-LNG PLANT-NEGATIVE SALVAGE 0.15% PER ANNUM

 

TRANSMISSION PLANT

ONSHORE

SOLAR TURBINES 4.97% PER ANNUM

ONSHORE PLANT (OTHER THAN TURBINES) 2.04% PER ANNUM

NEGATIVE SALVAGE (OTHER THAN TURBINES) 0.57% PER ANNUM

MAIDEN LATERAL 5.00% PER ANNUM

OFFSHORE

COMPOSITE 1.20% PER ANNUM

 

GENERAL PLANT DEPRECIATION IS CHARGED AT VARIOUS RATES BASED ON THE EXPECTED LIFE

 

ALL OF THE ABOVE DEPRECIATION AND NEGATIVE SALVAGE WAS COMPUTED ON DEPRECIABLE PLANT IN SERVICE BASED ON THE BALANCES AT THE END OF THE PRECEEDING MONTH.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Particulars Concerning Certain Income Deductions and Interest Charges Accounts

Report the information specified below, in the order given, for the respective income deduction and interest charges accounts.

  1. Miscellaneous Amortization (Account 425)-Describe the nature of items included in this account, the contra account charged, the total of amortization charges for the year, and the period of amortization.
  2. Miscellaneous Income Deductions-Report the nature, payee, and amount of other income deductions for the year as required by Accounts 426.1, Donations; 426.2, Life Insurance; 426.3, Penalties; 426.4, Expenditures for Certain Civic, Political and Related Activities; and 426.5, Other Deductions, of the Uniform System of Accounts. Amounts of less than $250,000 may be grouped by classes within the above accounts.
  3. Interest on Debt to Associated Companies (Account 430)-For each associated company that incurred interest on debt during the year, indicate the amount and interest rate respectively for (a) advances on notes, (b) advances on open account, (c) notes payable, (d) accounts payable, and (e) other debt, and total interest. Explain the nature of other debt on which interest was incurred during the year.
  4. Other Interest Expense (Account 431) - Report details including the amount and interest rate for other interest charges incurred during the year.
Line No.
DescriptionOfParticularsConcerningCertainIncomeDeductionsAndInterestChargesAccounts
Item
(a)
AmountOfParticularsConcerningCertainIncomeDeductionsAndInterestChargesAccounts
Amount
(b)
1
Account 425 - Miscellaneous Amortization
2
3
4
5
TOTAL Account 425 - Miscellaneous Amortization
6
Account 426.1 - Donations
7
8
9
10
TOTAL Account 426.1 - Donations
245,300
11
Account 426.2 - Life Insurance
12
13
14
15
TOTAL Account 426.2 - Life Insurance
16
Account 426.3 - Penalties
17
18
19
20
TOTAL Account 426.3 - Penalties
862,400
21
Account - 426.4 Expenditues for Certain Civic, Political, and Related Activities
22
23
24
25
TOTAL Account 426.3 - Penalties
493,860
26
Account 426.5 - Other Deductions
27
28
29
30
TOTAL Account 426.5 - Other Deductions
1,871,929
31
Account 430 - Interest on Debt to Associated Companies
32
33
34
35
TOTAL Account 430 - Interest on Debt to Associated Companies
60,062
36
Account 431 - Other Interest Expense
37
38
39
40
TOTAL Account 431 - Other Interest Expense
43,522,862
1
426.1 Donations
2
426.1 Various (Under $250,000)
245,300
3
TOTAL
245,300
4
426.3 Penalties
5
426.3 Reserve for Proposed Civil Penalty
779,150
6
426.3 Other
83,250
7
TOTAL
862,400
8
426.4 Expenditures for Certain Civic, Political and Related Activities
9
426.4 Professional Services
449,594
10
426.4 Company Association Dues
44,266
11
TOTAL
493,860
12
426.5 Miscellaneous Other Deductions
13
426.5 Project Development
2,043,765
14
426.5 ARO Trust Fund Fees
89,358
15
426.5 Reserve for Litigation
57,136
16
426.5 Escheat Check Voids
192,402
17
426.5 Other
125,928
18
TOTAL
1,871,929
19
430.0 Interest on Debt to Associated Companies
20
430.0 Letter of Credit Fees
60,062
21
TOTAL
60,062
22
431.0 Other Interest Expense
23
431.0 Interest on Dalton Capital Lease at 9%
23,897,764
24
431.0 Interest on Atlantic Sunrise Capital Lease at 10%
19,605,392
25
431.0 Other
19,706
26
TOTAL
43,522,862


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Regulatory Commission Expenses (Account 928)
  1. Report below details of regulatory commission expenses incurred during the current year (or in previous years, if being amortized) relating to formal cases before a regulatory body, or cases in which such a body was a party.
  2. In column (b) and (c), indicate whether the expenses were assessed by a regulatory body or were otherwise incurred by the utility.
  3. Show in column (k) any expenses incurred in prior years that are being amortized. List in column (a) the period of amortization.
  4. Identify separately all annual charge adjustments (ACA).
  5. List in column (f), (g), and (h) expenses incurred during year which were charges currently to income, plant, or other accounts.
  6. Minor items (less than $250,000) may be grouped.
Line No.
RegulatoryCommissionDescription
Description (Furnish name of regulatory commission or body the docket or case number and a description of the case)
(a)
RegulatoryExpensesAssessedByRegulatoryCommission
Assessed by Regulatory Commission
(b)
RegulatoryExpensesOfUtility
Expenses of Utility
(c)
RegulatoryCommissionExpensesAmount
Total Expenses to Date
(d)
OtherRegulatoryAssetsRegulatoryCommissionExpenses
Deferred in Account 182.3 at Beginning of Year
(e)
NameOfDepartmentRegulatoryCommissionExpensesCharged
Expenses Incurred During Year Charged Currently To Department
(f)
AccountNumberRegulatoryCommissionExpensesCharged
Expenses Incurred During Year Charged Currently To Account No.
(g)
RegulatoryComissionExpensesIncurredAndCharged
Expenses Incurred During Year Charged Currently To Amount
(h)
RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets
Expenses Incurred During Year Deferred to Account 182.3
(i)
DeferredRegulatoryCommissionExpensesAmortizedInContraAccount
Amortized During Year Contra Account
(j)
DeferredRegulatoryCommissionExpensesAmortized
Amortized During Year Amount
(k)
OtherRegulatoryAssetsRegulatoryCommissionExpenses
Deferred in Account 182.3 End of Year
(l)
1
Federal Energy Regulatory Commission RP87-177
4,528,989
4,528,989
2
Federal Energy Regulatory Commission RP18-1126
260,579
260,579
3
Federal Energy Regulatory Commission PL17-1
93,005
93,005
4
Federal Energy Regulatory Commission IN89-1
18,103
18,103
5
Federal Energy Regulatory Commission RM18-12
9,767
9,767
6
Federal Energy Regulatory Commission FA18-2
4,550
4,550
25
TOTAL
4,528,989
386,004
4,914,993


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Employee Pensions and Benefits (Account 926)
  1. Report below the items contained in Account 926, Employee Pensions and Benefits.
Line No.
Expense
(a)
Amount (in dollars)
(b)
1
Pensions - defined benefit plans
12,544,281
2
Pensions - other
3
Post-retirement benefits other than pensions (PBOP)
5,907,138
4
Post-employment benefit plans
282,828
5
Other (Specify)
(a)
555,824
6
Investment plus plan - employer contribution
8,276,552
7
Group insurance
18,340,137
8
Benefits transferred to construction and other accounts
11,983,326
9
Workers' compensation
160,905
40
Total
21,158,415


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: EmployeePensionsAndBenefits

 

 

EMPLOYEE BENEFIT PLAN FEES

$

102,541

LTD RESERVE

 

36,350

FRINGE FACTOR ADJUSTMENT

 

(694,715)

 

$

(555,824)


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Distribution of Salaries and Wages

Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals and Other Accounts, and enter such amounts in the appropriate lines and columns provided. Salaries and wages billed to the Respondent by an affiliated company must be assigned to the particular operating function(s) relating to the expenses.

In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used. When reporting detail of other accounts, enter as many rows as necessary numbered sequentially starting with 75.01, 75.02, etc.

Line No.
Classification
(a)
Direct Payroll Distribution
(b)
Payroll Billed by Affiliated Companies
(c)
Allocation of Payroll Charged for Clearing Accounts
(d)
Total
(e)
1
SalariesAndWagesElectricAbstract
Electric
2
SalariesAndWagesElectricOperationAbstract
Operation
3
SalariesAndWagesElectricOperationProduction
Production
4
SalariesAndWagesElectricOperationTransmission
Transmission
5
SalariesAndWagesElectricOperationDistribution
Distribution
6
SalariesAndWagesElectricCustomerAccounts
Customer Accounts
7
SalariesAndWagesElectricCustomerServiceAndInformational
Customer Service and Informational
8
SalariesAndWagesElectricSales
Sales
9
SalariesAndWagesElectricOperationAdministrativeAndGeneral
Administrative and General
10
SalariesAndWagesElectricOperation
TOTAL Operation (Total of lines 3 thru 9)
11
SalariesAndWagesElectricMaintenanceAbstract
Maintenance
12
SalariesAndWagesElectricMaintenanceProduction
Production
13
SalariesAndWagesElectricMaintenanceTransmission
Transmission
14
SalariesAndWagesElectricMaintenanceDistribution
Distribution
15
SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral
Administrative and General
16
SalariesAndWagesElectricMaintenance
TOTAL Maintenance (Total of lines 12 thru 15)
17
SalariesAndWagesElectricOperationAndMaintenanceAbstract
Total Operation and Maintenance
18
SalariesAndWagesElectricProduction
Production (Total of lines 3 and 12)
19
SalariesAndWagesElectricTransmission
Transmission (Total of lines 4 and 13)
20
SalariesAndWagesElectricDistribution
Distribution (Total of lines 5 and 14)
21
SalariesAndWagesElectricCustomerAccounts
Customer Accounts (line 6)
22
SalariesAndWagesElectricCustomerServiceAndInformational
Customer Service and Informational (line 7)
23
SalariesAndWagesElectricSales
Sales (line 8)
24
SalariesAndWagesElectricAdministrativeAndGeneral
Administrative and General (Total of lines 9 and 15)
25
SalariesAndWagesElectricOperationAndMaintenance
TOTAL Operation and Maintenance (Total of lines 18 thru 24)
26
SalariesAndWagesGasAbstract
Gas
27
SalariesAndWagesGasOperationAbstract
Operation
28
SalariesAndWagesGasOperationProductionManufacturedGas
Production - Manufactured Gas
29
SalariesAndWagesGasOperationProductionNaturalGas
Production - Natural Gas(Including Exploration and Development)
89,052
10,757
99,809
30
SalariesAndWagesGasOperationOtherGasSupply
Other Gas Supply
31
SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing
Storage, LNG Terminaling and Processing
5,301,706
13,204
5,314,910
32
SalariesAndWagesGasOperationTransmission
Transmission
76,158,915
1,485,507
13,985,727
91,630,149
33
SalariesAndWagesGasOperationDistribution
Distribution
34
SalariesAndWagesGasCustomerAccounts
Customer Accounts
35
SalariesAndWagesGasCustomerServiceAndInformational
Customer Service and Informational
36
SalariesAndWagesGasSales
Sales
37
SalariesAndWagesGasOperationAdministrativeAndGeneral
Administrative and General
21,420,593
1,264,660
13,820,089
36,505,342
38
SalariesAndWagesGasOperation
TOTAL Operation (Total of lines 28 thru 37)
102,970,266
2,774,128
27,805,816
133,550,210
39
SalariesAndWagesGasMaintenanceAbstract
Maintenance
40
SalariesAndWagesGasMaintenanceProductionManufacturedGas
Production - Manufactured Gas
41
SalariesAndWagesGasMaintenanceProductionNaturalGas
Production - Natural Gas(Including Exploration and Development)
3,550
18,841
15,291
42
SalariesAndWagesGasMaintenanceOtherGasSupply
Other Gas Supply
43
SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing
Storage, LNG Terminaling and Processing
853,284
71,688
924,972
44
SalariesAndWagesGasMaintenanceTransmission
Transmission
12,552,056
400,313
179,272
13,131,641
45
SalariesAndWagesGasMaintenanceDistribution
Distribution
46
SalariesAndWagesGasMaintenanceAdministrativeAndGeneral
Administrative and General
47
SalariesAndWagesGasMaintenance
TOTAL Maintenance (Total of lines 40 thru 46)
13,401,790
490,842
179,272
14,071,904
49
SalariesAndWagesGasOperationAndMaintenanceAbstract
Total Operation and Maintenance
50
SalariesAndWagesGasProductionManufacturedGas
Production - Manufactured Gas (Total of lines 28 and 40)
51
SalariesAndWagesGasProductionNaturalGas
Production - Natural Gas (Including Expl. and Dev.)(ll. 29 and 41)
85,502
29,598
115,100
52
SalariesAndWagesGasOtherGasSupply
Other Gas Supply (Total of lines 30 and 42)
53
SalariesAndWagesGasStorageLngTerminalingAndProcessing
Storage, LNG Terminaling and Processing (Total of ll. 31 and 43)
6,154,990
84,892
6,239,882
54
SalariesAndWagesGasTransmission
Transmission (Total of lines 32 and 44)
88,710,971
1,885,820
14,164,999
104,761,790
55
SalariesAndWagesGasDistribution
Distribution (Total of lines 33 and 45)
56
SalariesAndWagesGasCustomerAccounts
Customer Accounts (Total of line 34)
57
SalariesAndWagesGasCustomerServiceAndInformational
Customer Service and Informational (Total of line 35)
58
SalariesAndWagesGasSales
Sales (Total of line 36)
59
SalariesAndWagesGasAdministrativeAndGeneral
Administrative and General (Total of lines 37 and 46)
21,420,593
1,264,660
13,820,089
36,505,342
60
SalariesAndWagesGasOperationAndMaintenance
Total Operation and Maintenance (Total of lines 50 thru 59)
116,372,056
3,264,970
27,985,088
147,622,114
61
SalariesAndWagesOtherUtilityDepartmentsAbstract
Other Utility Departments
62
SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance
Operation and Maintenance
63
SalariesAndWagesOperationsAndMaintenance
TOTAL ALL Utility Dept. (Total of lines 25, 60, and 62)
116,372,056
3,264,970
27,985,088
147,622,114
64
SalariesAndWagesUtilityPlantAbstract
Utility Plant
65
SalariesAndWagesUtilityPlantConstructionAbstract
Construction (By Utility Departments)
66
SalariesAndWagesUtilityPlantConstructionElectricPlant
Electric Plant
67
SalariesAndWagesUtilityPlantConstructionGasPlant
Gas Plant
39,518,617
9,210,375
48,728,992
68
SalariesAndWagesUtilityPlantConstructionOther
Other
69
SalariesAndWagesUtilityPlantConstruction
TOTAL Construction (Total of lines 66 thru 68)
39,518,617
9,210,375
48,728,992
70
SalariesAndWagesPlantRemovalAbstract
Plant Removal (By Utility Departments)
71
SalariesAndWagesPlantRemovalElectricPlant
Electric Plant
72
SalariesAndWagesPlantRemovalGasPlant
Gas Plant
989,772
96,849
1,086,621
73
SalariesAndWagesPlantRemovalOther
Other
74
SalariesAndWagesPlantRemoval
TOTAL Plant Removal (Total of lines 71 thru 73)
989,772
96,849
1,086,621
75.1
Other Accounts (Specify) (footnote details)
(a)
10,615,044
(b)
207,540
10,822,584
76
TOTAL Other Accounts
10,615,044
207,540
10,822,584
77
TOTAL SALARIES AND WAGES
167,495,489
12,779,734
27,985,088
208,260,311


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: SalariesAndWagesOtherAccounts

 

ACCOUNTS RECEIVABLE FROM OTHERS (ACCOUNT 143)

$

111,635

ACCOUNTS RECEIVABLE FROM ASSOCIATED COMPANIES (ACCOUNT 146)

 

4,659,213

STORES EXPENSE UNDISTRIBUTED (ACCOUNT 163)

 

5,758

OTHER PRELIMINARY SURVEY & INVESTIGATION CHARGES (ACCOUNT 183.2)

 

(445,315)

MISCELLANEOUS DEFERRED DEBITS (ACCOUNT 186)

 

375,210

DEFERRED STOCK AMORTIZATION:

 

 

ACCOUNT 814

 

61,142

ACCOUNT 818

 

34,259

ACCOUNT 841

 

33,852

ACCOUNT 850

 

1,950,782

ACCOUNT 851

 

105,035

ACCOUNT 852

 

40,208

ACCOUNT 853

 

595,835

ACCOUNT 856

 

544,384

ACCOUNT 857

 

8,049

ACCOUNT 863

 

2,867

ACCOUNT 920

 

1,303,727

STOCK OPTION AMORTIZATION:

 

 

ACCOUNT 850

 

219,036

ACCOUNT 856

 

35,970

ACCOUNT 920

 

193,230

PERFORMANCE BASED AMORTIZATION:

 

 

ACCOUNT 850

 

368,278

ACCOUNT 851

 

15,853

ACCOUNT 856

 

37,248

ACCOUNT 920

 

358,788

 

$

10,615,044

 

 

Line

(b) Concept: SalariesAndWagesOtherAccounts

 

PRELIMINARY SURVEY & INVESTIGATION CHARGES (ACCOUNT 183.2)

$

158,528

MISCELLANEOUS DEFERRED DEBIT (ACCOUNT 186)

 

49,012

 

$

207,540


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Charges for Outside Professional and Other Consultative Services
  1. Report the information specified below for all charges made during the year included in any account (including plant accounts) for outside consultative and other professional services. These services include rate, management, construction, engineering, research, financial, valuation, legal, accounting, purchasing, advertising,labor relations, and public relations, rendered for the respondent under written or oral arrangement, for which aggregate payments were made during the year to any corporation partnership, organization of any kind, or individual (other than for services as an employee or for payments made for medical and related services) amounting to more than $250,000, including payments for legislative services, except those which should be reported in Account 426.4 Expenditures for Certain Civic, Political and Related Activities. (a) Name of person or organization rendering services. (b) Total charges for the year.
  2. Sum under a description “Other”, all of the aforementioned services amounting to $250,000 or less.
  3. Total under a description “Total”, the total of all of the aforementioned services.
  4. Charges for outside professional and other consultative services provided by associated (affiliated) companies should be excluded from this schedule and be reported on Page 358, according to the instructions for that schedule.
Line No.
NameOfPersonOrOrganizationRenderingProfessionalOrConsultativeServices
Description
(a)
ChargesForOutsideProfessionalAndOtherConsultativeServices
Amount (in dollars)
(b)
1
AECOM TECHNICAL SERVICES INC
6,327,638
2
ALLEGIS GLOBAL SOLUTIONS INC
9,772,070
3
APTIM ENVIRONMENTAL & INFRASTRUCTURE INC
271,832
4
ARK ENGINEERING & TECHNICAL SERVICES INC
411,410
5
BARHITE EXCAVATING LLC
270,185
6
BL COMPANIES ARCHITECTS ENGINEERS LANDSCAPE ARCHITECTS
7,189,482
7
BLACK & VEATCH CORP
5,309,509
8
BRAVO GROUP INC
730,863
9
BUCHANAN INGERSOLL & ROONEY PC
307,089
10
BURNS & MCDONNELL ENGINEERING COMPANY
1,690,816
11
CARDNO INC
378,216
12
CH2M HILL ENGINEERS INC
573,540
13
CLEVELAND INTEGRITY SERVICES INC
782,526
14
COASTAL CHEMICAL CO LLC
1,123,293
15
COATES FIELD SERVICE INC
261,756
16
COMMERCE CONSTRUCTION CORPORATION
1,507,600
17
CONTREX ENERGY SERVICES LLC
299,611
18
CRESCENT POWER SYSTEMS INC
395,956
19
DON E BOWER INC
426,999
20
DOYLE LAND SERVICES INC
2,467,044
21
ECOLOGY & ENVIRONMENT INC
4,762,440
22
ENVIRONMENTAL RESOURCES MANAGEMENT SOUTHWEST INC
2,574,669
23
EPCON PARTNERS INC
920,384
24
EPIQ EDISCOVERY SOLUTIONS INC
495,744
25
EROSION COMPANY INC
1,258,844
26
EROSION CONTROL PRODUCTS INC
1,641,607
27
FAITHFUL+GOULD INC
354,783
28
FEHLINGER CONSTRUCTION GROUP LLC
280,465
29
FULKRUM TECHNICAL RESOURCES INC
300,499
30
GOVERNOR CONTROL SYSTEMS INC
262,029
31
GULF INTERSTATE ENGINEERING CO
288,715
32
HALEY & ALDRICH INC
417,756
33
HARGROVE & ASSOC INC
534,809
34
HAWK TECHNICAL SERVICES LLC
517,208
35
HDR ENGINEERING INC
585,298
36
HUNT GUILLOT & ASSOCIATES LLC
4,148,434
37
KEAN MILLER LLP
862,861
38
LAKE SUPERIOR CONSULTING LLC
4,575,251
39
LARSON DESIGN GROUP INC
1,347,093
40
LATHAM WAGNER STEELE & LEHMAN PC
791,641
41
LONQUIST FIELD SERVICE LLC
3,198,628
42
M&H ENTERPRISES INC
2,883,241
43
MEARS GROUP INC
917,487
44
MERJENT INC
401,784
45
MOTT MACDONALD LLC
3,366,224
46
MUSTANG OF NEW JERSEY INC
388,698
47
OCEANEERING INTERNATIONAL INC
481,303
48
OGCS AMERICAS INC
401,982
49
PELICAN ENERGY CONSULTANTS LLC
1,644,352
50
PREMIER INSPECTIONS & CONSULTANTS LLC
250,518
51
PRIDE OIL & GAS PROPERTIES INC
321,193
52
PUBLIC STRATEGIES IMPACT LLC
400,000
53
QUALITY INTEGRATED SERVICES INC
457,686
54
ROSEN USA INC
323,500
55
R-S-H ENGINEERING INC
266,027
56
RUTTER & ROY LLP
285,214
57
S&ME INC
2,669,647
58
SHERMCO INDUSTRIES INC
270,819
59
SOLAR TURBINES INC
1,704,754
60
STAFURSKY PAVING CO INC
1,142,893
61
STRESS ENGINEERING SERVICES INC
255,202
62
TAILING INTERNATIONAL LLC
317,311
63
TETRA TECH INC
350,008
64
TRC ENVIRONMENTAL CORP
449,825
65
UNIVERSAL FIELD SERVICES INC
5,917,495
66
VINCENT ENDEAVORS LLC
401,752
67
VORTECH CONTRACTING INC
278,565
68
WHM CONSULTING INC
494,127
69
WOOD GROUP USA INC
9,344,076
70
WRIGHT & TALISMAN PC
268,637
71
OTHER
10,866,805
72
TOTAL
118,137,718
73
TOTAL


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Transactions with Associated (Affiliated) Companies
  1. Report below the information called for concerning all goods or services received from or provided to associated (affiliated) companies amounting to more than $250,000.
  2. Sum under a description “Other”, all of the aforementioned goods and services amounting to $250,000 or less.
  3. Total under a description “Total”, the total of all of the aforementioned goods and services.
  4. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote the basis of the allocation.
Line No.
DescriptionOfTheGoodOrService
Description of the Good or Service
(a)
NameOfAssociatedAffiliatedCompany
Name of Associated/Affiliated Company
(b)
AccountsChargedOrCreditedTransactionsWithAssociatedAffiliatedCompanies
Account(s) Charged or Credited
(c)
Amount Charged or Credited
(d)
1
Goods or Services Provided by Affiliated Company
2
Capital Work Orders
Williams Companies, Inc.
1,649,141
3
Internal Legal
Williams Companies, Inc.
628,724
4
Internal Legal
Williams Companies, Inc.
1,259
5
Internal Legal
Williams Companies, Inc.
54,500
6
Internal Legal
Williams Companies, Inc.
20,620
7
Internal Legal
Williams Companies, Inc.
1,510,150
8
Letter of Credit Fees
Williams Companies, Inc.
60,062
9
Contracted Services
Williams Companies, Inc.
327,943
10
Other Outside Services
Williams Companies, Inc.
33,393
11
Shipping
Williams Companies, Inc.
243,769
12
Stock Based Compensation
Williams Companies, Inc.
(z)
5,908,543
13
Employee Stock Purchase Plan
Williams Companies, Inc.
(aa)
384,379
14
(a)
Direct/Dedicated Service Charges
Williams Companies, Inc.
64,594
15
(b)
Direct/Dedicated Service Charges
Williams Companies, Inc.
2,908,324
16
(c)
Specific Corporate Allocations
Williams Companies, Inc.
35,382,316
17
(d)
General Corporate Allocations
Williams Companies, Inc.
63,426,353
18
Employee Travel & Entertainment Expense
Williams Companies, Inc.
(ab)
7,981,430
19
Direct Assignment Payroll Benefits - G&A,ES,CS,SOD
Williams Companies, Inc.
(ac)
7,287,889
20
Direct Assignment Payroll Taxes - G&A,ES,CS,SOD
Williams Companies, Inc.
(ad)
947,275
21
Direct Assignment Payroll - G&A,ES,CS,SOD
Williams Companies, Inc.
(ae)
12,302,340
22
(e)
Allocated Payroll - ES,CS,SOD
Williams Companies, Inc.
9,702,958
23
(f)
Allocated Payroll - ES,CS,SOD
Williams Companies, Inc.
256,555
24
(g)
Allocated Payroll - ES,CS,SOD
Williams Companies, Inc.
1,733,716
25
(h)
Allocated Payroll - ES,CS,SOD
Williams Companies, Inc.
1,245,662
26
(i)
Allocated Payroll - ES,CS,SOD
Williams Companies, Inc.
571,516
27
(j)
Allocated Payroll - ES,CS,SOD
Williams Companies, Inc.
179,272
28
(k)
Allocated Payroll - ES,CS,SOD
Williams Companies, Inc.
11,680,280
29
(l)
Allocated Non-Payroll Costs - ES,CS,SOD
Williams Companies, Inc.
2,972,760
30
(m)
Allocated Non-Payroll Costs - ES,CS,SOD
Williams Companies, Inc.
97,678
31
(n)
Allocated Non-Payroll Costs - ES,CS,SOD
Williams Companies, Inc.
860,023
32
(o)
Allocated Non-Payroll Costs - ES,CS,SOD
Williams Companies, Inc.
34,623
33
(p)
Allocated Non-Payroll Costs - ES,CS,SOD
Williams Companies, Inc.
262,620
34
(q)
Allocated Non-Payroll Costs - ES,CS,SOD
Williams Companies, Inc.
38,552
35
(r)
Allocated Non-Payroll Costs - ES,CS,SOD
Williams Companies, Inc.
6,409,770
36
Payroll Benefits
Cardinal Operating Company, LLC
1,336
37
Payroll Taxes
Cardinal Operating Company, LLC
222
38
Payroll
Cardinal Operating Company, LLC
2,879
39
TOTAL CARDINAL OPERATING COMPANY, LLC
4,437
40
Payroll Benefits
Northwest Pipeline LLC
40,583
41
Payroll Benefits
Northwest Pipeline LLC
2,239
42
Payroll Taxes
Northwest Pipeline LLC
6,460
43
Payroll Taxes
Northwest Pipeline LLC
356
44
Payroll
Northwest Pipeline LLC
83,879
45
Payroll
Northwest Pipeline LLC
1,591
46
Payroll
Northwest Pipeline LLC
1,382
47
Payroll
Northwest Pipeline LLC
1,642
48
Inventory Transfer
Northwest Pipeline LLC
1,317
49
TOTAL NORTHWEST PIPELINE LLC
139,449
50
Cashout Purchases
Williams Field Services - Gulf Coast Company LLC
2,992,557
51
TOTAL Williams Field Services - Gulft Coast Company LLC
2,992,557
52
Cashout Purchases
WFS - Liquids LLC
22,136
53
TOTAL WFS - Liquids LLC
22,136
54
Cashout Purchases
Williams Energy Resources LLC
464,117
55
TOTAL WILLIAMS ENERGY RESOURCES LLC
464,117
56
Cashout Purchases
Williams Field Services Company , LLC
1,952,328
57
TOTAL WILLIAMS FIELD SERVICES COMPANY, LLC
1,952,328
58
Payroll Benefits
Williams Partners Operating LLC
88,025
59
Payroll Benefits
Williams Partners Operating LLC
3,004
60
Payroll Benefits
Williams Partners Operating LLC
21,843
61
Payroll Benefits
Williams Partners Operating LLC
361
62
Payroll Benefits
Williams Partners Operating LLC
8,299
63
Payroll Benefits
Williams Partners Operating LLC
98,436
64
Payroll Taxes
Williams Partners Operating LLC
13,861
65
Payroll Taxes
Williams Partners Operating LLC
485
66
Payroll Taxes
Williams Partners Operating LLC
3,386
67
Payroll Taxes
Williams Partners Operating LLC
57
68
Payroll Taxes
Williams Partners Operating LLC
1,301
69
Payroll Taxes
Williams Partners Operating LLC
15,420
70
Payroll
Williams Partners Operating LLC
180,029
71
Payroll
Williams Partners Operating LLC
6,299
72
Payroll
Williams Partners Operating LLC
43,952
73
Payroll
Williams Partners Operating LLC
735
74
Payroll
Williams Partners Operating LLC
16,895
75
Payroll
Williams Partners Operating LLC
8,352
76
Payroll
Williams Partners Operating LLC
13,004
77
Payroll
Williams Partners Operating LLC
844
78
Payroll
Williams Partners Operating LLC
139,270
79
Payroll
Williams Partners Operating LLC
29,133
80
Payroll
Williams Partners Operating LLC
345
81
Payroll
Williams Partners Operating LLC
3,344
82
Payroll
Williams Partners Operating LLC
2,450
83
Payroll
Williams Partners Operating LLC
2,130
84
Payroll
Williams Partners Operating LLC
1,371
85
(s)
Corporate Overhead Allocation
Williams Partners Operating LLC
4,062
86
Inventory Transfer
Williams Partners Operating LLC
21,639
87
Capital
Williams Partners Operating LLC
915,064
88
TOTAL WILLIAMS PARTNERS OPERATING LLC (WPO)
1,643,396
89
Payroll Benefits
WPS (Gulfstream operating expenses)
137
90
Payroll Taxes
WPS (Gulfstream operating expenses)
21
91
Payroll
WPS (Gulfstream operating expenses)
276
92
TOTAL WILLIAMS PIPELINE SERVICES LLC (WPS)
434
93
(GULFSTREAM OPERATING EXPENSES)
94
(t)
Corporate Overhead Allocation
Williams Partners L.P.
1,712,718
95
(u)
Allocated Payroll - Operating Area Management
Williams Partners L.P.
475,319
96
(v)
Allocated Payroll - Operating Area Management
Williams Partners L.P.
2,139,811
97
(w)
Allocated Non-Payroll Cost-Operating Area Management
Williams Partners L.P.
223,375
98
(x)
Allocated Non-Payroll Cost-Operating Area Management
Williams Partners L.P.
480,632
99
TOTAL WILLIAMS PARTNERS L.P. (WPZ)
5,031,855
100
Capital Transfer
Constitution Pipeline Company, LLC
2,333,828
101
TOTAL CONSTITUTION PIPELINE COMPANY, LLC
2,333,828
102
(GULFSTREAM OPERATING EXPENSES)
103
Employee Payroll
Williams WPC-1, LLC
(af)
142,699,259
104
Employee Bonus
Williams WPC-1, LLC
(ag)
21,994,092
105
Payroll Tax Expense
Williams WPC-1, LLC
11,945,450
106
Severance
Williams WPC-1, LLC
400
107
Severance
Williams WPC-1, LLC
658,092
108
Self-Insurance General Liability
Williams WPC-1, LLC
108,469
109
Other Employee Expense
Williams WPC-1, LLC
(ah)
365,604
110
Other Compensation Expense
Williams WPC-1, LLC
(ai)
544,652
111
Fringe Factor Accrual
Williams WPC-1, LLC
242,473
112
Fringe Factor Accrual
Williams WPC-1, LLC
80,403
113
Workers Compensation
Williams WPC-1, LLC
160,905
114
Post-Employment Benefits other than Pension
Williams WPC-1, LLC
5,907,138
115
Group Insurance Expense
Williams WPC-1, LLC
18,775,311
116
Retirement Plan Contribution
Williams WPC-1, LLC
12,544,281
117
PTO Accrual
Williams WPC-1, LLC
(aj)
1,177,076
118
Investment Plus Plan
Williams WPC-1, LLC
8,087,612
119
A&G Supplemental Rettirement
Williams WPC-1, LLC
282,828
120
LTD Medical & Self-Insured Salary
Williams WPC-1, LLC
823,582
121
Employee Travel & Entertainment Expense
Williams WPC-1, LLC
(ak)
3,019,942
122
(y)
TOTAL WILLIAMS WPC-1, LLC
215,795,323
19
TOTAL
(al)
176,890,933
20
Goods or Services Provided for Affiliated Company
21
Payroll Benefits
Williams Companies, Inc.
1,189
22
Payroll Benefits
Williams Companies, Inc.
3,635
23
Payroll Benefits
Williams Companies, Inc.
192,422
24
Payroll Taxes
Williams Companies, Inc.
141
25
Payroll Taxes
Williams Companies, Inc.
481
26
Payroll Taxes
Williams Companies, Inc.
30,879
27
Payroll
Williams Companies, Inc.
15,417
28
Payroll
Williams Companies, Inc.
6,247
29
Payroll
Williams Companies, Inc.
29,786
30
Payroll
Williams Companies, Inc.
1,162
31
Payroll
Williams Companies, Inc.
29,315
32
Payroll
Williams Companies, Inc.
570
33
Payroll
Williams Companies, Inc.
6,682
34
Payroll
Williams Companies, Inc.
333,528
35
TOTAL WILLIAMS COMPANIES, INC.
651,454
36
Payroll Benefits
Pine Needle Operating Company, LLC
612,547
37
Payroll Taxes
Pine Needle Operating Company, LLC
97,721
38
Payroll
Pine Needle Operating Company, LLC
1,099
39
Payroll
Pine Needle Operating Company, LLC
374,838
40
Payroll
Pine Needle Operating Company, LLC
12,334
41
Payroll
Pine Needle Operating Company, LLC
9,553
42
Payroll
Pine Needle Operating Company, LLC
4,212
43
Payroll
Pine Needle Operating Company, LLC
729,593
44
Payroll
Pine Needle Operating Company, LLC
10,879
45
Payroll
Pine Needle Operating Company, LLC
126,667
46
A&G Overhead
Pine Needle Operating Company, LLC
53,007
47
Inventory Transfer
Pine Needle Operating Company, LLC
5,192
48
(am)
Capital
Pine Needle Operating Company, LLC
1,281
49
Purge and Test
Pine Needle Operating Company, LLC
449
50
TOTAL PINE NEEDLE OPERATING COMPANY, LLC
2,039,372
51
Payroll Benefits
Cardinal Operating Company, LLC
284,037
52
Payroll Taxes
Cardinal Operating Company, LLC
44,994
53
Payroll
Cardinal Operating Company, LLC
4,000
54
Payroll
Cardinal Operating Company, LLC
16,356
55
Payroll
Cardinal Operating Company, LLC
2,888
56
Payroll
Cardinal Operating Company, LLC
184,020
57
Payroll
Cardinal Operating Company, LLC
264,407
58
Payroll
Cardinal Operating Company, LLC
17,427
59
Payroll
Cardinal Operating Company, LLC
123
60
Payroll
Cardinal Operating Company, LLC
95,113
61
A&G Overhead
Cardinal Operating Company, LLC
29,649
62
Inventory Transfer
Cardinal Operating Company, LLC
506
63
(an)
Capital
Cardinal Operating Company, LLC
1,225
64
TOTAL CARDINAL OPERATING COMPANY, LLC
944,745
65
Payroll Benefits
Northwest Pipeline LLC
260,828
66
Payroll Taxes
Northwest Pipeline LLC
41,620
67
Payroll
Northwest Pipeline LLC
306
68
Payroll
Northwest Pipeline LLC
1,894
69
Payroll
Northwest Pipeline LLC
10,943
70
Payroll
Northwest Pipeline LLC
7,647
71
Payroll
Northwest Pipeline LLC
1,174
72
Payroll
Northwest Pipeline LLC
518,526
73
(ao)
Rent
Northwest Pipeline LLC
150,094
74
(ap)
Depreciation
Northwest Pipeline LLC
2,806
75
(aq)
Depreciation
Northwest Pipeline LLC
10,784
76
Inventory Transfer
Northwest Pipeline LLC
6,245
77
(ar)
Capital
Northwest Pipeline LLC
111,359
78
TOTAL NORTHWEST PIPEINE LLC
1,124,226
79
Cashout Sales
Williams Field Services - Gulf Coast Company LLC
3,498,273
80
Transportation of Liquids
Williams Field Services - Gulf Coast Company LLC
12,558
81
TOTAL Williams Field Services - Gulf Coast Company LLC
3,510,831
82
Transportation of Liquids
WFS - Liquids LLC
2,920
83
TOTAL WFS - Liquids LLC
2,920
84
Cashout Sales
Williams Energy Resources LLC
1,003,162
85
Transportation of Gas of Others Through Transmission Facilities
Williams Energy Resources LLC
2,191,552
86
TOTAL WILLIAMS ENERGY RESOURCES LLC
3,194,714
87
Cashout Sales
Williams Field Services Company LLC
3,389,279
88
TOTAL WILLIAMS FIELD SERVICES COMPANY, LLC
3,389,279
89
Platform and Meter O&M Fees
Williams Field Services Group, LLC
59,508
90
Payroll Benefits
Williams Field Services Group, LLC
15,562
91
Payroll Taxes
Williams Field Services Group, LLC
2,416
92
Payroll
Williams Field Services Group, LLC
(bm)
11,344
93
Payroll
Williams Field Services Group, LLC
20,029
94
Payroll Benefits
Williams Partners Operating LLC
930,527
95
Payroll Taxes
Williams Partners Operating LLC
148,331
96
Payroll
Williams Partners Operating LLC
258,264
97
Payroll
Williams Partners Operating LLC
47,519
98
Payroll
Williams Partners Operating LLC
252,542
99
Payroll
Williams Partners Operating LLC
709,164
100
Payroll
Williams Partners Operating LLC
43,214
101
Payroll
Williams Partners Operating LLC
465,540
102
Payroll
Williams Partners Operating LLC
149,192
103
(as)
Operating Area Allocation-Payroll Benefits
Williams Partners Operating LLC
87,778
104
(at)
Operating Area Allocation-Payroll Taxes
Williams Partners Operating LLC
12,079
105
(au)
Operating Area Allocation-Payroll
Williams Partners Operating LLC
142
106
(av)
Operating Area Allocation-Payroll
Williams Partners Operating LLC
28,270
107
(aw)
Operating Area Allocation-Payroll
Williams Partners Operating LLC
3,111
108
(ax)
Operating Area Allocation-Payroll
Williams Partners Operating LLC
45,718
109
(ay)
Operating Area Allocation-Payroll
Williams Partners Operating LLC
3,772
110
(az)
Operating Area Allocation-Payroll
Williams Partners Operating LLC
1,678
111
(ba)
Operating Area Allocation-Payroll
Williams Partners Operating LLC
435
112
(bb)
Operating Area Allocation-Payroll
Williams Partners Operating LLC
73,723
113
(bc)
Operating Area Allocation-Other Costs
Williams Partners Operating LLC
567
114
(bd)
Operating Area Allocation-Other Costs
Williams Partners Operating LLC
1,502
115
(be)
Operating Area Allocation-Other Costs
Williams Partners Operating LLC
365
116
(bf)
Operating Area Allocation-Other Costs
Williams Partners Operating LLC
7,693
117
(bg)
Rent
Williams Partners Operating LLC
1,460,889
118
(bh)
Depreciation
Williams Partners Operating LLC
27,256
119
(bi)
Depreciation
Williams Partners Operating LLC
105,075
120
Capital
Williams Partners Operating LLC
1,451
121
TOTAL WILLIAMS PARTNERS OPERATING LLC (WPO)
4,865,797
122
Payroll Benefits
WPS (Gulfstream operating expenses)
982,899
123
Payroll Taxes
WPS (Gulfstream operating expenses)
156,521
124
Payroll
WPS (Gulfstream operating expenses)
184,233
125
Payroll
WPS (Gulfstream operating expenses)
168,502
126
Payroll
WPS (Gulfstream operating expenses)
7,904
127
Payroll
WPS (Gulfstream operating expenses)
92,909
128
Payroll
WPS (Gulfstream operating expenses)
1,140,448
129
Payroll
WPS (Gulfstream operating expenses)
42,435
130
Payroll
WPS (Gulfstream operating expenses)
164,972
131
(GULFSTREAM OPERATING EXPENSES)
132
Payroll
WPS (Gulfstream operating expenses)
231,256
133
A&G Overhead
WPS (Gulfstream operating expenses)
1,055,647
134
Capital Transfer
WPS (Gulfstream operating expenses)
2,823
135
TOTAL WILLIAMS PIPELINE SERVICES LLC (WPS)
4,230,549
136
(GULFSTREAM OPERATING EXPENSES)
137
Payroll Benefits
Williams Partners L.P.
175
138
Payroll Taxes
Williams Partners L.P.
27
139
Payroll
Williams Partners L.P.
352
140
TOTAL WILLIAMS PARTNERS L.P. (WPZ)
554
141
Payroll Benefits
Constitution Pipeline Company, LLC
43,551
142
Payroll Taxes
Constitution Pipeline Company, LLC
6,894
143
Payroll
Constitution Pipeline Company, LLC
30,010
144
Payroll
Constitution Pipeline Company, LLC
1,035
145
Payroll
Constitution Pipeline Company, LLC
7,210
146
Payroll
Constitution Pipeline Company, LLC
51,292
147
A&G Overhead
Constitution Pipeline Company, LLC
57,864
148
Capital Transfer
Constitution Pipeline Company, LLC
57,947
149
Payroll Benefits
Other
1,778
150
Payroll Taxes
Other
291
151
Payroll
Other
3,770
152
(bj)
Rent
Other
213,465
153
(bk)
Depreciation
Other
3,966
154
(bl)
Depreciation
Other
15,214
155
TOTAL OTHER
(bn)
238,484
40
TOTAL
(bo)(bp)
108,859


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionOfTheGoodOrService

 

WILLIAMS COMPANIES, INC.

ENTERPRISE SUPPORT SERVICES PROVIDED BY WILLIAMS COMPANIES, INC. FOR GENERAL AND ADMINISTRATIVE (G&A), ENGINEERING SERVICES (ES), CENTRAL SERVICES (CS), AND SAFETY AND OPERATIONAL DISCIPLINE (SOD) ARE CHARGED TO TRANSCO AND OTHER FRANCHISES VIA ONE OF THREE METHODS: (1) DIRECT ASSIGNMENT OF ALL COSTS ASSOCIATED WITH CORPORATE PERSONNEL WHO ARE DEDICATED TO SERVE THE NEEDS OF A SPECIFIC OPERATING AREA OR FRANCHISE; (2) SPECIFIC ALLOCATIONS BASED ON A RELATIONSHIP WITH THE DELIVERY OF SERVICES, AS IN THE CASE OF SOME HUMAN RESOURCE SERVICES COSTS THAT ARE ALLOCATED BASED ON EMPLOYEE HEADCOUNT; OR (3) GENERAL ALLOCATIONS USING THE MODIFIED MASSACHUSETTS FORMULA FOR RESIDUAL OVERHEAD COSTS THAT ARE NOT READILY ASSIGNABLE TO A PARTICULAR OPERATING AREA OR FRANCHISE VIA DIRECT ASSIGNMENT OR SPECIFIC ALLOCATION.

(b) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.:14 COLUMN: A

(c) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.:14 COLUMN: A

(d) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.:14 COLUMN: A

(e) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(f) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(g) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(h) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(i) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(j) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(k) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(l) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(m) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(n) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(o) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(p) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(q) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(r) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358 LINE NO.: 14 COLUMN: A

(s) Concept: DescriptionOfTheGoodOrService

 

WILLIAMS PARTNERS OPERATING LLC (WPO)

G&A EMPLOYEES’ DIRECT ASSIGNMENT PAYROLL AND NON-PAYROLL CHARGES TO WPO (DIRECT PARENT OF TRANSCO) IN SUPPORT OF WPO’S MAJOR FERC-REGULATED SUBSIDIARIES WERE ALLOCATED TO THOSE FRANCHISES, INCLUDING TRANSCO, USING THE MODIFIED MASSACHUSETTS FORMULA.

(t) Concept: DescriptionOfTheGoodOrService

 

WILLIAMS PARTNERS L.P. (WPZ)

WPZ CORPORATE OVERHEAD ALLOCATION ENDED AUGUST 2018 WITH THE DISSOLUTION OF WPZ. WPZ INCURRED GENERAL AND ADMINISTRATIVE COSTS FOR BOARD OF DIRECTORS, REGULATORY AND RATING AGENCY FEES, LEGAL, AUDIT, INSURANCE, OPERATIONS, TAXES AND OTHER EXPENSES. THESE COSTS WERE CHARGED TO TRANSCO AND OTHER FRANCHISES OWNED BY THE PARTNERSHIP. GENERALLY, UNLESS THE COSTS INCURRED WERE FOR THE DIRECT BENEFIT OF ONE OF THE WPZ FRANCHISES – IN WHICH CASE ALL OF THE COSTS WERE CHARGED TO THE BENEFITTING FRANCHISE – THE MODIFIED MASSACHUSETTS ALLOCATION FORMULA WAS EMPLOYED. HOWEVER, WPZ COULD HAVE EMPLOYED OTHER ALLOCATION METHODOLOGIES IF DOING SO WOULD MOST ACCURATELY ASSIGN SHARED COSTS TO THE BENEFITTING FRANCHISES. DURING 2018, THE NATURE OF COSTS INCURRED BY WPZ RESULTED IN ONLY THE MODIFIED MASSACHUSETTS FORMULA METHODOLOGY BEING EMPLOYED TO ALLOCATE COSTS TO TRANSCO AND THE OTHER WPZ FRANCHISES.

(u) Concept: DescriptionOfTheGoodOrService

 

WILLIAMS PARTNERS L.P. (WPZ)

CORPORATE PAYROLL AND NON-PAYROLL CHARGES FOR THE BENEFIT OF THE ATLANTIC GULF OPERATING AREA THAT ARE NOT SPECIFIC TO A FRANCHISE ARE ALLOCATED TO FRANCHISES INCLUDED IN THE ATLANTIC GULF OPERATING AREA, INCLUDING TRANSCO, VIA ONE OF THREE METHODS: (1) DIRECT ASSIGNMENT OF ALL COSTS ASSOCIATED WITH CORPORATE PERSONNEL WHO ARE DEDICATED TO SERVE THE NEEDS OF A SPECIFIC OPERATING AREA OR FRANCHISE; (2) SPECIFIC ALLOCATIONS BASED ON A RELATIONSHIP WITH THE DELIVERY SERVICES, AS IN THE CASE OF SOME HUMAN RESOURCE SERVICES COSTS THAT ARE ALLOCATED BASED IN EMPLOYEE HEADCOUNT; OR (3) GENERAL ALLOCATIONS USING THE MODIFIED MASSACHUSETTS FORMULA FOR RESIDUAL OVERHEAD COSTS THAT ARE NOT READILY ASSIGNABLE TO A PARTICULAR OPERATING AREA OR FRANCHISE VIA DIRECT ASSIGNMENT OR SPECIFIC ALLOCATION. THE ATLANTIC GULF OPERATING AREA INCLUDES NON-REGULATED FRANCHISES AND TRANSCO. ALLOCATION TO WPO IS FOR THE NON-REGULATED FRANCHISES IN THE OPERATING AREA.

(v) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.7 LINE NO.: 9 COLUMN: A

(w) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.7 LINE NO.: 9 COLUMN: A

(x) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.7 LINE NO.: 9 COLUMN: A

 

 

 

(y) Concept: NameOfAssociatedAffiliatedCompany

 

WILLIAMS WPC-1, LLC

AS PART OF WILLIAMS’ RESTRUCTURING OF ITS BUSINESS, EFFECTIVE AS OF FEBRUARY 16, 2010, ALL OF OUR FORMER EMPLOYEES WERE TRANSFERRED TO OUR AFFILIATE, TRANSCO PIPELINE SERVICES LLC (TPS). ON FEBRUARY 17, 2010, WE ENTERED INTO AN ADMINISTRATIVE SERVICES AGREEMENT PURSUANT TO WHICH TPS PROVIDES PERSONNEL, FACILITIES, GOODS AND EQUIPMENT NOT OTHERWISE PROVIDED BY US THAT ARE NECESSARY TO OPERATE OUR BUSINESS. IN RETURN, WE REIMBURSE TPS FOR ALL DIRECT AND INDIRECT EXPENSES IT INCURS OR PAYMENTS IT MAKES (INCLUDING SALARY, BONUS, INCENTIVE COMPENSATION AND BENEFITS) IN CONNECTION WITH THESE SERVICES.

 

ON FEBRUARY 13, 2013 AN ASSIGNMENT AGREEMENT WAS EXECUTED EFFECTIVE JANUARY 1, 2013 ASSIGNING RIGHTS FROM TPS TO WILLIAMS WPC-1, LLC.

(z) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS COMPANIES, INC.

STOCK BASED COMPENSATION - VARIOUS

 

 

814

$ 61,142

 

818

34,259

 

841

33,852

 

850

2,538,096

 

851

120,888

 

852

40,208

 

853

595,836

 

856

617,602

 

857

8,049

 

863

2,867

 

920

1,855,744

 

TOTAL

$ 5,908,543

(aa) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS COMPANIES, INC.

EMPLOYEE STOCK PURCHASE PLAN - VARIOUS

 

 

814

$ 4,075

 

818

6,797

 

821

309

 

834

157

 

841

3,259

 

850

133,811

 

851

16,915

 

852

3,869

 

853

60,159

 

856

68,972

 

857

1,194

 

862

233

 

863

5,106

 

864

534

 

865

463

 

920

78,526

 

TOTAL

$ 384,379

(ab) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS COMPANIES, INC.

EMPLOYEE TRAVEL & ENTERTAINMENT EXPENSE - VARIOUS

 

 

 

 

 

107

$ 4,160,968

 

108

55,727

 

183

125,039

 

186

29,577

 

750

20,152

 

753

1,511

 

756

3,742

 

759

365

 

761

6,983

 

762

25

 

814

6,277

 

816

55

 

818

45,047

 

821

4,363

 

832

224

 

834

4,721

 

836

640

 

840

393

 

841

33,679

 

850

897,314

 

851

60,076

 

852

95,734

 

853

622,855

 

856

753,016

 

857

39,822

 

859

8,160

 

862

12,207

 

863

59,099

 

864

8,424

 

865

2,590

 

866

174

 

921

918,602

 

925

1,137

 

926

494

 

928

2,238

 

TOTAL

$ 7,981,430

 

 

(ac) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS COMPANIES, INC.

DIRECT ASSIGNMENT PAYROLL BENEFITS – G&A, ES, CS, SOD - VARIOUS

 

 

107

$ 5,238,212

 

108

54,272

 

163

2,296

 

183

151,208

 

186

19,182

 

856

208,964

 

922

641,353

 

926

972,402

 

TOTAL

$ 7,287,889

(ad) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS COMPANIES, INC.

DIRECT ASSIGNMENT PAYROLL TAXES – G&A, ES, CS, SOD - VARIOUS

 

 

107

$ 680,598

 

108

7,019

 

163

301

 

183

19,561

 

186

2,474

 

408

237,322

 

TOTAL

$ 947,275

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(ae) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS COMPANIES, INC.

DIRECT ASSIGNMENT PAYROLL – G&A, ES, CS, SOD - VARIOUS

 

 

107

$ 8,839,256

 

108

91,163

 

163

3,904

 

183

254,042

 

186

32,118

 

750

22,170

 

756

1,691

 

759

1,688

 

764

157,079

 

766

699

 

814

3,141

 

816

433

 

818

4,350

 

821

2,372

 

830

283

 

834

43,488

 

836

23,822

 

840

2,908

 

843

53

 

850

652,352

 

851

609

 

852

74,226

 

853

393,067

 

856

176,112

 

857

3,879

 

859

4,286

 

861

57,760

 

863

125,656

 

864

49,809

 

867

18,277

 

920

1,261,647

 

TOTAL

$ 12,302,340

(af) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS WPC-1, LLC

EMPLOYEE PAYROLL – VARIOUS

 

 

753

$ 15,272

 

764

2,338

 

814

382,682

 

816

41,295

 

817

16,482

 

818

2,424,231

 

820

104,584

 

821

149,234

 

824

29,080

 

831

19,866

 

832

20,457

 

833

68,537

 

834

499,407

 

835

656

 

836

159,748

 

840

13,980

 

841

2,060,796

 

850

32,339,378

 

851

3,055,476

 

852

2,763,146

 

853

31,883,290

 

856

31,593,630

 

857

1,838,564

 

859

59,544

 

861

62,437

 

862

3,469,790

 

863

4,340,745

 

864

3,748,631

 

865

983,620

 

866

1,175

 

867

230,117

 

920

20,321,071

 

TOTAL

$ 142,699,259

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(ag) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS WPC-1, LLC

EMPLOYEE BONUS - VARIOUS

 

 

107

$ 1,757,499

 

814

100,688

 

816

1,003

 

817

697

 

818

357,535

 

820

11,667

 

821

13,879

 

824

2,825

 

832

470

 

833

272

 

834

14,760

 

836

7,817

 

840

1,358

 

841

251,800

 

850

5,862,872

 

851

402,850

 

852

332,606

 

853

4,576,287

 

856

3,765,951

 

857

111,255

 

859

1,684

 

861

6,067

 

862

103,644

 

863

291,614

 

864

120,965

 

865

60,515

 

866

114

 

867

19,209

 

920

3,816,189

 

TOTAL

$ 21,994,092

(ah) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS WPC-1, LLC

OTHER EMPLOYEE EXPENSE - VARIOUS

 

 

818

$ 26,898

 

841

2,328

 

850

102,822

 

851

10,249

 

852

14,461

 

853

(5,421)

 

856

111,643

 

863

(5,128)

 

921

5,705

 

926

102,047

.

TOTAL

$ 365,604

 

 

(ai) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS WPC-1, LLC

OTHER COMPENSATION EXPENSE - VARIOUS

 

 

814

$ 4,800

 

818

1,500

 

841

19,182

 

850

89,480

 

852

5,000

 

853

94,042

 

856

22,711

 

857

4,000

 

862

4,000

 

863

7,160

 

920

292,777

 

TOTAL

$ 544,652

(aj) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS WPC-1, LLC

PTO ACCRUAL - VARIOUS

 

 

753

$ 121

 

764

17

 

814

3,687

 

816

326

 

817

117

 

818

21,953

 

820

1,011

 

821

1,201

 

824

281

 

831

166

 

832

168

 

833

580

 

834

3,649

 

835

4

 

836

1,245

 

841

17,908

 

850

256,763

 

851

26,003

 

852

23,220

 

853

264,696

 

856

257,981

 

857

15,632

 

859

523

 

861

690

 

862

28,866

 

863

30,467

 

864

32,487

 

865

8,217

 

866

15

 

867

2,293

 

920

176,789

 

TOTAL

$ 1,177,076

 

(ak) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS WPC-1, LLC

EMPLOYEE TRAVEL & ENTERTAINMENT EXPENSE - VARIOUS

 

 

 

 

 

107

$ 2,227,512

 

108

55,403

 

183

5,633

 

186

12,494

 

750

290

 

756

3,657

 

814

542

 

818

4,960

 

821

13

 

831

3,495

 

834

585

 

840

100

 

841

817

 

850

277,549

 

851

889

 

852

2,373

 

853

68,785

 

856

254,564

 

857

1,116

 

859

13,923

 

862

1,617

 

863

38,289

 

921

45,306

 

928

30

 

TOTAL

$ 3,019,942

(al) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies
Duplicate fact discrepancy. Schedule: 358 - Schedule - Transactions with Associated (Affiliated) Companies - Provided by Affiliated Company, Row: 19, Column: d, Value: 0
(am) Concept: DescriptionOfTheGoodOrService

 

PINE NEEDLE OPERATING COMPANY, LLC

CAPITAL FOR COMMON SYSTEMS HARDWARE AND DEVELOPED SOFTWARE COSTS ALLOCATED USING THE MODIFIED MASSACHUSETTS FORMULA.

(an) Concept: DescriptionOfTheGoodOrService

 

CARDINAL OPERATING COMPANY, LLC

CAPITAL FOR COMMON SYSTEMS HARDWARE AND DEVELOPED SOFTWARE COSTS ALLOCATED USING THE MODIFIED MASSACHUSETTS FORMULA.

 

(ao) Concept: DescriptionOfTheGoodOrService

 

NORTHWEST PIPELINE LLC

THE WILLIAMS TOWER – HOUSTON BUILDING RENT IS ALLOCATED BASED ON EMPLOYEE LABOR COSTS.

(ap) Concept: DescriptionOfTheGoodOrService

 

NORTHWEST PIPELINE LLC

DEPRECIATION OF FURNITURE, EQUIPMENT, AND LEASEHOLD IMPROVEMENTS IN THE WILLIAMS TOWER – HOUSTON IS ALLOCATED BASED ON EMPLOYEE LABOR COSTS.

(aq) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358.3 LINE NO.:30 COLUMN: A

(ar) Concept: DescriptionOfTheGoodOrService

 

NORTHWEST PIPELINE LLC

CAPITAL FOR COMMON SYSTEMS HARDWARE AND DEVELOPED SOFTWARE COSTS ALLOCATED USING THE MODIFIED MASSACHUSETTS FORMULA.

(as) Concept: DescriptionOfTheGoodOrService

 

WILLIAMS PARTNERS OPERATING LLC (WPO)

EMPLOYEES’ DIRECT ASSIGNMENT PAYROLL AND NON-PAYROLL CHARGES FOR THE BENEFIT OF THE ATLANTIC GULF OPERATING AREA THAT ARE NOT SPECIFIC TO A FRANCHISE ARE ALLOCATED TO FRANCHISES INCLUDED IN THE ATLANTIC GULF OPERATING AREA BASED ON THE MODIFIED MASSACHUSETTS FORMULA. THE ATLANTIC GULF OPERATING AREA INCLUDES NON-REGULATED FRANCHISES AND TRANSCO. ALLOCATION TO WPO IS FOR THE NON-REGULATED FRANCHISES IN THE OPERATING AREA.

(at) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(au) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(av) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(aw) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(ax) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(ay) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(az) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(ba) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(bb) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(bc) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(bd) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(be) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(bf) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE 358.5 LINE NO.: 30 COLUMN: A

(bg) Concept: DescriptionOfTheGoodOrService

 

WILLIAMS PARTNERS OPERATING LLC (WPO)

THE WILLIAMS TOWER – HOUSTON BUILDING RENT IS ALLOCATED BASED ON EMPLOYEE LABOR COSTS.

 

(bh) Concept: DescriptionOfTheGoodOrService

 

WILLIAMS PARTNERS OPERATING LLC (WPO)

DEPRECIATION OF FURNITURE, EQUIPMENT, AND LEASEHOLD IMPROVEMENTS IN THE WILLIAMS TOWER – HOUSTON IS ALLOCATED BASED ON EMPLOYEE LABOR COSTS.

(bi) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE FOR PAGE: 358.6 LINE NO.: 26 COLUMN: A

(bj) Concept: DescriptionOfTheGoodOrService

 

OTHER

THE WILLIAMS TOWER – HOUSTON BUILDING RENT IS ALLOCATED BASED ON EMPLOYEE LABOR COSTS.

(bk) Concept: DescriptionOfTheGoodOrService

 

OTHER

DEPRECIATION OF FURNITURE, EQUIPMENT AND LEASEHOLD IMPROVEMENTS IN THE WILLIAMS TOWER – HOUSTON IS ALLOCATED BASED ON EMPLOYEE LABOR COST.

(bl) Concept: DescriptionOfTheGoodOrService

 

REFER TO FOOTNOTE PAGE: 358.8 LINE NO.: 25 COLUMN: A

(bm) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies

 

WILLIAMS FIELD SERVICES GROUP, LLC

PAYROLL – VARIOUS

 

 

 

850

$ (6,339)

 

818

(3,719)

 

841

(1,286)

 

TOTAL

$ (11,344)

(bn) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies

 

OTHER INCLUDES

 

 

 

 

$ 1,242

MARSH RESOURCES, INC.

 

7,094

WILLIAMS PIPELINE SERVICES LLC

 

215,555

WILLIAMS PARTNERS OPERATING LLC (INCLUDES GULFSTREAM)

 

14,593

WILLIAMS PARTNERS OPERATING LLC (INCLUDES CONSTITUTION)

 

$ 238,484

(bo) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies
Duplicate fact discrepancy. Schedule: 358 - Schedule - Transactions with Associated (Affiliated) Companies - Provided by Affiliated Company, Row: 40, Column: d, Value: -255803
(bp) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies
Duplicate fact discrepancy. Schedule: 358 - Schedule - Transactions with Associated (Affiliated) Companies - Provided by Affiliated Company, Row: 40, Column: d, Value: 0

Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Compressor Stations
  1. Report below details concerning compressor stations. Use the following subheadings: field compressor stations, products extraction compressor stations, underground storage compressor stations, transmission compressor stations, distribution compressor stations, and other compressor stations.
  2. For column (a), indicate the production areas where such stations are used. Group relatively small field compressor stations by production areas. Show the number of stations grouped. Identify any station held under a title other than full ownership. State in a footnote the name of owner or co-owner, the nature of respondent's title, and percent of ownership if jointly owned.
Line No.
NameAndLocationOfCompressorStation
Name and Location of Compressor Station
(a)
TypeOfCompressor
Compressor Type
(b)
NumberOfUnitsAtCompressorStation
Number of Units at Compressor Station
(c)
CertificatedHorsepowerForEachCompressorStation
Certificated Horsepower for Each Compressor Station
(d)
PlantCost
Plant Cost
(e)
ExpensesExceptDepreciationAndTaxesFuel
Expenses (except depreciation and taxes) Fuel
(f)
ExpensesExceptDepreciationAndTaxesPower
Expenses (except depreciation and taxes) Power
(g)
ExpensesExceptDepreciationAndTaxesOther
Expenses (except depreciation and taxes) Other
(h)
GasForCompressorFuel
Gas for Compressor Fuel in Dth
(i)
ElectricityForCompressorStation
Electricity for Compressor Station in kWh
(j)
CompressorHoursOfOperationDuringYear
Operational Data Total Compressor Hours of Operation During Year
(k)
NumberOfCompressorsOperatedAtTimeOfStationPeak
Operational Data Number of Compressors Operated at Time of Station Peak
(l)
DateOfStationPeak
Date of Station Peak
(m)
1
Field: Field Compressor Stations:
0
2
Texas and Louisiana - 4 Field Locations
4,622,231
0
3
Field: Total Field Compressor Stations
4,622,231
0
4
Underground Storage: Underground Storage Compressor Stations
0
5
Underground Storage: No. 54 Washington Storage Field, Louisiana
3
33,000
131,399,492
1,767,904
10,147,572
586,790
(e)
6733
2
08/02/2018
6
Underground Storage: No. 77 Eminence Storage Field, Mississippi
4
15,635
127,040,746
885,399
2,293,983
290,940
(f)
5582
3
04/11/2018
7
Underground Storage: No. 530 Leidy-Tamarack Storage Field, Pennsylvania
(c)
61,960,247
3,145,962
1,094,275
0
8
Underground Storage: No. 535 Wharton Storage Field, Pennsylvania
5
8,500
(d)
58,434,835
1,385,309
1,879,135
0
3
03/16/2019
9
Underground Storage: Total Underground Storage
12
57,135
378,835,320
5,799,265
14,921,139
2,756,865
(g)
12315
10
Transmission: Transmission Compressor Stations:
0
11
Transmission: No 23 Victoria County, Texas
2
21,600
58,777,202
51,496
980,114
56,564
0
1
03/31/2019
12
Transmission: No. 30 El Campo, Texas
7
17,500
40,082,744
329,530
7,560,518
103,004
(h)
6487
3
02/17/2019
13
Transmission: No. 35 Houston, Texas
2
14,910
26,759,423
5,755
134,390
892,466
1,655
2,193,013
(i)
607
1
11/01/2018
14
Transmission: No. 40 Sour Lake, Texas
6
15,000
37,297,405
14,445
1,496,334
7,601
(j)
333
2
01/27/2019
15
Transmission: No 42 Starks Louisiana
2
32,000
81,953,351
5,338,778
75,828
3,523
1,741,772
(k)
10469
2
11/03/2018
16
(a)
Transmission: No. 44 Johnson's Bayou, Louisiana
5
43,085
118,288,051
5,319,168
119,768
57,659
1,746,412
(l)
9521
2
02/24/2019
17
Transmission: No. 45 Lake Charles, Louisiana
8
19,750
42,678,937
1,667,148
17,402,744
565,925
(m)
36057
8
02/19/2019
18
Transmission: No. 50 Eunice, Louisiana
1
10,310
33,978,276
5,196
3,270,541
1,752
0
19
Transmission: No. 51 Eunice, Louisiana
5
10,000
11,037,568
286,439
103,023
(n)
6400
3
12/16/2018
20
Transmission: No. 52 Eunice, Louisiana
3
6,000
5,050,321
103,848
21,885
(o)
1438
12/16/2018
21
Transmission: No. 60 St. Francisville, Louisiana
13
37,640
59,912,274
2,625,899
2,081,044
808,218
(p)
40622
10
01/16/2019
22
Transmission: No. 61 Ethel, Louisiana
2
3,050
3,759,927
0
23
Transmission: No. 62 Humphries, Louisiana
9
24,820
63,161,809
26,419
1,030,105
12,988
(q)
1184
4
11/29/2018
24
Transmission: No. 63 Convent, Louisiana
8
17,960
14,306,859
968
1,115,686
310
(r)
69
2
08/29/2018
25
Transmission: No. 65 Kentwood, Louisiana
6
26,400
37,059,417
55,875
894,428
17,417
(s)
623
3
01/16/2019
26
Transmission: No. 70 Tylertown, Mississippi
6
47,390
44,646,196
3,124,781
1,234,413
1,028,892
(t)
9073
3
11/28/2018
27
Transmission: No. 80 Sandersville, Mississippi
18
71,000
59,877,371
3,953,929
5,938
3,892,614
1,179,476
(u)
37314
12
04/18/2018
28
Transmission: No. 82 Coden, Alabama
3
25,766
22,876,491
421,951
0
29
Transmission: No. 83 Citronelle, Alabama
1
16,000
30,601,148
2,122,652
166,970
659,195
(v)
6119
1
09/27/2018
30
Transmission: No. 84 Butler, Alabama
2
32,000
78,438,600
1,072,868
214,254
326,264
(w)
1267
2
01/21/2019
31
Transmission: No. 85 Butler, Alabama
4
38,150
97,052,301
2,745,889
424
311,831
916,005
(x)
6890
1
10/13/2018
32
Transmission: No. 90 Myrtlewood, Alabama
18
80,620
75,525,559
9,820,706
4,052,244
3,073,356
(y)
74218
18
01/29/2019
33
Transmission: No. 95 Marion Junction, Alabama
3
48,000
94,450,322
1,699,335
62,833
376,515
498,126
(z)
4148
3
01/10/2019
34
Transmission: No. 100 Billingsley, Alabama
7
93,880
84,509,322
1,924,651
9,269,783
1,724,482
540,571
126,280,584
(aa)
10213
4
01/10/2019
35
Transmission: No. 105 Rockford, Alabama
4
65,500
83,013,591
5,078,912
151,645
1,540,340
(ab)
12415
4
02/01/2019
36
Transmission: No. 110 Wadley, Alabama
17
82,850
117,220,466
7,286,909
122,032
2,349,777
2,149,505
(ac)
51017
17
01/21/2019
37
Transmission: No. 115 Newnan, Georgia
3
62,950
67,248,852
7,351,675
244,028
82,716,102
(ad)
5442
3
01/31/2019
38
Transmission: No 116 Whitesburg, Georgia
2
21,830
32,060,702
1,774,655
2,753
333,078
586,756
(ae)
4441
1
01/24/2019
39
Transmission: No. 120 Stockbridge, Georgia
18
71,530
94,003,625
5,752,835
2,431,892
2,623,782
1,783,601
49,779,925
(af)
90806
17
01/21/2019
40
Transmission: No. 125 Monroe, Georgia
5
49,800
68,812,020
1,692,827
432,908
635,900
459,124
6,719,200
(ag)
5626
4
01/31/2019
41
Transmission: No. 130 Comer, Georgia
18
59,290
63,471,497
5,427,389
4,914
3,388,856
1,570,349
(ah)
46481
17
01/31/2019
42
Transmission: No. 135 Anderson South Carolina
1
20,500
34,084,471
410,483
407,285
83,178
(ai)
556
1
01/21/2019
43
Transmission: No. 140 Spartanburg, South Carolina
15
60,755
81,275,095
4,404,628
2,645,956
1,297,900
(aj)
49464
14
01/21/2019
44
Transmission: No. 145 Grover, North Carolina
3
37,500
39,387,525
2,425
3,062,449
805,075
732
34,699,813
(ak)
3840
3
01/31/2019
45
Transmission: No. 150 Davidson, North Carolina
16
54,300
104,316,552
1,837,400
10,125
2,870,923
505,086
(al)
30565
10
07/02/2018
46
Transmission: No. 155 Lexington, North Carolina
6
22,300
33,600,926
118,138
585,972
33,812
(am)
807
4
04/20/2018
47
Transmission: No. 160 Reidsville, North Carolina
16
54,520
81,120,662
945,245
44,685
2,446,839
245,307
(an)
13305
12
11/02/2018
48
Transmission: No. 165 Chatham, Virginia
12
26,950
53,957,541
3,705,034
1,736,025
1,304,895
(ao)
26260
10
11/02/2018
49
Transmission: No. 166 Chatham, Virginia
4
43,660
92,773,023
43,694
171,343
(ap)
14925
2
03/16/2019
50
Transmission: No. 167 South Hill, Virginia
2
7,800
15,400,784
29,017
306,762
7,588
(aq)
169
1
02/11/2019
51
Transmission: No. 170 Appomattox, Virginia
11
33,200
73,592,472
88,014
1,727,838
30,540
(ar)
1451
8
09/25/2018
52
Transmission: No. 175 Scottsville, Virginia
1
33,000
44,395,910
2,487
1,859,786
475,936
666
28,425,416
(as)
2023
1
11/03/2018
53
Transmission: No. 180 Orange, Virginia
14
34,020
54,210,609
1,382,831
2,071,444
536,054
(at)
32268
12
11/03/2018
54
Transmission: No. 185 Manassas, Virginia
11
45,000
120,377,896
751,203
1,075,775
2,385,984
255,650
8,947,229
(au)
15402
10
10/18/2018
55
Transmission: No. 190 Ellicott City, Maryland
13
59,250
168,244,033
773,912
2,605,129
325,309
(av)
1261
1
03/25/2019
56
Transmission: No. 195 Delta, Pennsylvania
4
26,000
75,704,772
89,155
3,562,848
1,170,549
26,841
53,422,523
(aw)
7979
2
11/03/2018
57
Transmission: No. 196 Cecil County, Maryland
1
4,000
28,353,103
1,089
262,928
293
(ax)
2036
1
11/02/2018
58
Transmission: No. 200 Malvern, Pennsylvania
13
33,000
72,423,312
448,336
2,563,811
118,504
(ay)
7066
12
01/31/2019
59
Transmission: No. 203 Chesterfield, New Jersey
1
30,500
91,880,441
779
425
0
60
Transmission: No. 205 Lawrenceville, New Jersey
3
57,000
139,305,927
1,271,375
774,103
7,471,112
(az)
334
2
01/21/2019
61
Transmission: No: 207 Middlesex, New Jersey
3
26,400
67,137,536
6,765
3,028,198
786,976
2,223
25,672,654
(ba)
6038
1
01/31/2019
62
Transmission: No: 303 Roseland Boro, New Jersey
1
27,500
89,562,831
12,313
356,413
559,108
3,817
2,087,057
(bb)
126
1
11/23/2018
63
Transmission: No. 505 Centerville, New Jersey
8
16,000
53,898,034
102,925
2,977
1,161,776
18,627
(bc)
1211
8
01/31/2019
64
Transmission: No. 515 Bear Creek, Pennsylvania
8
64,000
112,156,871
7,719,379
3,402,266
2,388,975
(bd)
37627
6
01/31/2019
65
Transmission: No. 517 Benton, Pennsylvania
6
88,000
155,871,619
2,098,811
1,184,124
661,646
(be)
333
1
05/23/2018
66
Transmission: No. 520 Salladasburg, Pennsylvania
9
71,700
140,599,612
583,998
3,025
1,578,930
168,307
(bf)
4204
8
02/26/2019
67
Transmission: No. 605 Factoryville, Pennsylvania
2
30,000
41,852,798
27,244
26,635,386
0
68
Transmission: No. 610 Milville, Pennsylvania
2
40,000
71,164,950
967
46,325
477
34,622,753
0
2
03/09/2019
69
Transmission: Total Transmission Compressor Stations
394
2,213,686
3,884,560,932
94,824,636
34,824,932
93,668,153
29,516,938
489,672,767
(bg)
738530
70
Other: Other Compressor Stations:
0
71
(b)
Other: No. 240 Hackensack Meadows, New Jersey
5
4,320
74,747,764
579,497
4,131,230
185,512
(bh)
8947
2
10/14/2018
72
Other: Total Other Compressor Stations
5
4,320
74,747,764
579,497
4,131,230
185,512
(bi)
8947
73
Other: TOTAL Compressor Stations
411
2,275,141
4,342,766,247
101,203,398
34,824,932
112,720,522
32,459,315
489,672,767
(bj)
759792
25
Total


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NameAndLocationOfCompressorStation

COMPRESSION WAS IDLE DURING 2018

(b) Concept: NameAndLocationOfCompressorStation

INCLUDES COST OF COMPRESSOR STATION DWELLINGS.

(c) Concept: PlantCost

LEIDY COMPRESSOR STATION IS OWNED BY TRANSCO, TEXAS EASTERN TRANSMISSION CORPORATION, AND DOMINION TRANSMISSION. THE PLANT REPORTED REPRESENTS TRANSCO'S 25% INTEREST IN SUCH STATION.

(d) Concept: PlantCost

WHARTON COMPRESSOR STATION IS OWNED BY TRANSCO, NATIONAL FUEL, AND CENTRAL PENN GAS. THE PLANT REPORTED REPRESENTS TRANSCO'S 80% INTEREST IN SUCH STATION.

(e) Concept: CompressorHoursOfOperationDuringYear
Original value: 6733
(f) Concept: CompressorHoursOfOperationDuringYear
Original value: 5582
(g) Concept: CompressorHoursOfOperationDuringYear
Original value: 12315
(h) Concept: CompressorHoursOfOperationDuringYear
Original value: 6487
(i) Concept: CompressorHoursOfOperationDuringYear
Original value: 607
(j) Concept: CompressorHoursOfOperationDuringYear
Original value: 333
(k) Concept: CompressorHoursOfOperationDuringYear
Original value: 10469
(l) Concept: CompressorHoursOfOperationDuringYear
Original value: 9521
(m) Concept: CompressorHoursOfOperationDuringYear
Original value: 36057
(n) Concept: CompressorHoursOfOperationDuringYear
Original value: 6400
(o) Concept: CompressorHoursOfOperationDuringYear
Original value: 1438
(p) Concept: CompressorHoursOfOperationDuringYear
Original value: 40622
(q) Concept: CompressorHoursOfOperationDuringYear
Original value: 1184
(r) Concept: CompressorHoursOfOperationDuringYear
Original value: 69
(s) Concept: CompressorHoursOfOperationDuringYear
Original value: 623
(t) Concept: CompressorHoursOfOperationDuringYear
Original value: 9073
(u) Concept: CompressorHoursOfOperationDuringYear
Original value: 37314
(v) Concept: CompressorHoursOfOperationDuringYear
Original value: 6119
(w) Concept: CompressorHoursOfOperationDuringYear
Original value: 1267
(x) Concept: CompressorHoursOfOperationDuringYear
Original value: 6890
(y) Concept: CompressorHoursOfOperationDuringYear
Original value: 74218
(z) Concept: CompressorHoursOfOperationDuringYear
Original value: 4148
(aa) Concept: CompressorHoursOfOperationDuringYear
Original value: 10213
(ab) Concept: CompressorHoursOfOperationDuringYear
Original value: 12415
(ac) Concept: CompressorHoursOfOperationDuringYear
Original value: 51017
(ad) Concept: CompressorHoursOfOperationDuringYear
Original value: 5442
(ae) Concept: CompressorHoursOfOperationDuringYear
Original value: 4441
(af) Concept: CompressorHoursOfOperationDuringYear
Original value: 90806
(ag) Concept: CompressorHoursOfOperationDuringYear
Original value: 5626
(ah) Concept: CompressorHoursOfOperationDuringYear
Original value: 46481
(ai) Concept: CompressorHoursOfOperationDuringYear
Original value: 556
(aj) Concept: CompressorHoursOfOperationDuringYear
Original value: 49464
(ak) Concept: CompressorHoursOfOperationDuringYear
Original value: 3840
(al) Concept: CompressorHoursOfOperationDuringYear
Original value: 30565
(am) Concept: CompressorHoursOfOperationDuringYear
Original value: 807
(an) Concept: CompressorHoursOfOperationDuringYear
Original value: 13305
(ao) Concept: CompressorHoursOfOperationDuringYear
Original value: 26260
(ap) Concept: CompressorHoursOfOperationDuringYear
Original value: 14925
(aq) Concept: CompressorHoursOfOperationDuringYear
Original value: 169
(ar) Concept: CompressorHoursOfOperationDuringYear
Original value: 1451
(as) Concept: CompressorHoursOfOperationDuringYear
Original value: 2023
(at) Concept: CompressorHoursOfOperationDuringYear
Original value: 32268
(au) Concept: CompressorHoursOfOperationDuringYear
Original value: 15402
(av) Concept: CompressorHoursOfOperationDuringYear
Original value: 1261
(aw) Concept: CompressorHoursOfOperationDuringYear
Original value: 7979
(ax) Concept: CompressorHoursOfOperationDuringYear
Original value: 2036
(ay) Concept: CompressorHoursOfOperationDuringYear
Original value: 7066
(az) Concept: CompressorHoursOfOperationDuringYear
Original value: 334
(ba) Concept: CompressorHoursOfOperationDuringYear
Original value: 6038
(bb) Concept: CompressorHoursOfOperationDuringYear
Original value: 126
(bc) Concept: CompressorHoursOfOperationDuringYear
Original value: 1211
(bd) Concept: CompressorHoursOfOperationDuringYear
Original value: 37627
(be) Concept: CompressorHoursOfOperationDuringYear
Original value: 333
(bf) Concept: CompressorHoursOfOperationDuringYear
Original value: 4204
(bg) Concept: CompressorHoursOfOperationDuringYear
Original value: 738530
(bh) Concept: CompressorHoursOfOperationDuringYear
Original value: 8947
(bi) Concept: CompressorHoursOfOperationDuringYear
Original value: 8947
(bj) Concept: CompressorHoursOfOperationDuringYear
Original value: 759792

Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
Gas Storage Projects
  1. Report injections and withdrawals of gas for all storage projects used by respondent.
Line No.
Item
(a)
GasDeliveredToStorageThatBelongToRespondent
Gas Belonging to Respondent (Dth)
(b)
GasDeliveredToStorageThatBelongToOthers
Gas Belonging to Others (Dth)
(c)
GasDeliveredToStorage
Total Amount (Dth)
(d)
STORAGE OPERATIONS (in Dth)
1
Gas Delivered to Storage
2
January
4,280,337
3,089,889
7,370,226
3
February
1,225,502
2,782,891
4,008,393
4
March
600,286
4,043,306
4,643,592
5
April
540,678
12,256,505
11,715,827
6
May
825,868
20,982,568
20,156,700
7
June
451,332
19,963,864
19,512,532
8
July
2,286,065
18,247,000
15,960,935
9
August
1,619,723
16,010,985
17,630,708
10
September
585,501
15,948,326
16,533,827
11
October
60,078
14,125,283
14,065,205
12
November
4,003,971
3,381,864
7,385,835
13
December
2,282,441
3,275,110
5,557,551
14
TOTAL (Total of lines 2 thru 13)
(a)
10,433,740
134,107,591
144,541,331
15
Gas Withdrawn from Storage
16
January
7,523,196
39,267,371
31,744,175
17
February
4,320,799
25,435,824
21,115,025
18
March
719,454
25,778,229
26,497,683
19
April
2,944,010
6,627,310
9,571,320
20
May
1,434,887
703,626
2,138,513
21
June
620,298
315,552
935,850
22
July
571,578
1,027,188
1,598,766
23
August
1,672,507
1,032,212
2,704,719
24
September
2,186,485
1,379,190
3,565,675
25
October
386,081
4,526,499
4,140,418
26
November
3,388,953
16,453,273
19,842,226
27
December
211,735
22,632,993
22,421,258
28
TOTAL (Total of lines 16 thru 27)
1,096,361
145,179,267
146,275,628


Name of Respondent:


Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:


04/12/2019
Year/Period of Report:


End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: GasDeliveredToStorageThatBelongToRespondent

STORAGE FLEX VOLUME ACTIVITY FOR ALL STORAGE FACILITIES IS REPORTED IN

COLUMN B.

 

CUSTOMERS’ STORAGE VOLUME FOR ALL STORAGE FACILITIES IS REPORTED

IN COLUMN C.

 

THE PHYSICAL STORAGE VOLUME ACTIVITY FOR ALL STORAGE FACILITIES IS REPORTED

IN COLUMN D.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Gas Storage Projects
  1. On line 4, enter the total storage capacity certificated by FERC.
  2. Report total amount in Dth or other unit, as applicable on lines 2, 3, 4, 7. If quantity is converted from Mcf to Dth, provide conversion factor in a footnote.
Line No.
Item
(a)
Total Amount
(b)
StorageOperationsAbstract
STORAGE OPERATIONS
1
GasInReservoirTopOrWorkingGas
Top or Working Gas End of Year
2,435,377
2
GasInReservoirCushionGasIncludingNativeGas
Cushion Gas (Including Native Gas)
95,977,494
3
GasInReservoir
Total Gas in Reservoir (Total of line 1 and 2)
98,412,871
4
CertificatedStorageCapacity
Certificated Storage Capacity
209,385,921
5
NumberOfInjectionWithdrawalWells
Number of Injection - Withdrawal Wells
102
6
NumberOfObservationWells
Number of Observation Wells
35
7
MaximumDaysWithdrawalFromStorage
Maximum Days' Withdrawal from Storage
2,170,591
8
DateOfMaximumDaysWithdrawal
Date of Maximum Days' Withdrawal
02/19/2019
9
LngTerminalCompanies
LNG Terminal Companies (in Dth)
10
NumberOfTanks
Number of Tanks
11
CapacityOfTanks
Capacity of Tanks
12
LngVolumeAbstract
LNG Volume
13
ReceivedAtShipRail
Received at "Ship Rail"
14
TransferredToTanks
Transferred to Tanks
15
WithdrawnFromTanks
Withdrawn from Tanks
16
BoilOffVaporizationLoss
"Boil Off" Vaporization Loss


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Transmission Lines
  1. Report below, by state, the total miles of transmission lines of each transmission system operated by respondent at end of year.
  2. Report separately any lines held under a title other than full ownership. Designate such lines with an asterisk, in column (b) and in a footnote state the name of owner, or co-owner, nature of respondent's title, and percent ownership if jointly owned.
  3. Report separately any line that was not operated during the past year. Enter in a footnote the details and state whether the book cost of such a line, or any portion thereof, has been retired in the books of account, or what disposition of the line and its book costs are contemplated.
  4. Report the number of miles of pipe to one decimal point.
Line No.
DesignationIdentificationOfLineOrGroupOfLines
Designation (Identification) of Line or Group of Lines
(a)
StateOfPipelineCompany
State
(b)
TypeOfOperationAndOwnership
Operation Type
(c)
IndicationOfOwnerships
*
(d)
LengthOfTransmissionLinesOfTransmissionSystems
Total Miles of Pipe
(e)
1
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: TEXAS
644.4
2
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: LOUISIANA
1,572.6
3
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: MISSISSIPPI
610.6
4
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: ALABAMA
1,083.3
5
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: GEORGIA
691.1
6
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: SOUTH CAROLINA
413.7
7
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: NORTH CAROLINA
586
8
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: VIRGINIA
934.8
9
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: MARYLAND
245.9
10
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: PENNSYLVANIA
1,040.1
11
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: NEW JERSEY
564.6
12
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: DELAWARE
1.7
13
OPERATED BY RESPONDENT ONSHORE AND STATE WATERS: NEW YORK
27.3
14
OPERATED BY RESPONDENT FEDERAL WATERS
544.1
15
(a)
ONSHORE AND STATE WATERS NOT OPER. BY RESP. LESS THAN FULL OWNERSHIP: TEXAS
6.9
16
(b)
ONSHORE AND STATE WATERS OPER. BY RESP. LESS THAN FULL OWNERSHIP: TEXAS
57.1
17
(c)
ONSHORE AND STATE WATERS NOT OPER. BY RESP. LESS THAN FULL OWNERSHIP: LOUISIANA
1.3
18
(d)
ONSHORE AND STATE WATERS OPER. BY RESP. LESS THAN FULL OWNERSHIP: LOUISIANA
46.8
19
(e)
ONSHORE AND STATE WATERS OPER. BY RESP. LESS THAN FULL OWNERSHIP: MISSISSIPPI
19.5
20
(f)
ONSHORE AND STATE WATERS OPER. BY RESP. LESS THAN FULL OWNERSHIP: ALABAMA
128.4
21
(g)
ONSHORE AND STATE WATERS OPER. BY RESP. LESS THAN FULL OWNERSHIP: GEORGIA
106.1
22
(h)
ONSHORE AND STATE WATERS OPER. BY RESP. LESS THAN FULL OWNERSHIP: PENNSYLVANIA
176.8
23
(i)
FEDERAL WATERS LESS THAN FULL OWNERSHIP OPER. BY RESP.
47.6
24
(j)
FEDERAL WATERS LESS THAN FULL OWNERSHIP NOT OPER. BY RESP.
48.3
25
OPERATED BY RESPONDENT
9,542.5
26
NOT OPERATED BY RESPONDENT
56.5
25
TOTAL


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DesignationIdentificationOfLineOrGroupOfLines

SUMMARY OF JOINTLY OWNED TRANSMISSION LINES NOT OPERATED BY TRANSCO-TEXAS ONSHORE AND STATE WATERS

 

1) 2.90 MILES OF 4" -TRANSCO 75%, EL PASO NATURAL GAS COMPANY 25%

 

2) 4.00 MILES OF 4"- TRANSCO 86%, NORTHERN NATURAL GAS COMPANY 14%

(b) Concept: DesignationIdentificationOfLineOrGroupOfLines

SUMMARY OF JOINTLY OWNED TRANSMISSION LINES OPERATED BY TRANSCO-TEXAS ONSHORE AND STATE WATERS

 

1) 0.50 MILES OF 24"- TRANSCO 38.124%, GULF SOUTH 61.876%

 

2) 1.08 MILES OF 30"- TRANSCO 70.1755%, COLUMBIA GULF TRANSMISSION 21.0526%, TC OFFSHORE 8.7719%

 

3) 23.21 MILES OF 36"- TRANSCO 54.18%, TENNESSEE GAS PIPELINE COMPANY 27.07%, COLUMBIA GULF TRANSMISSION 16%, NORTHERN NATURAL GAS COMPANY 2.75%

 

4) 32.31 MILES OF 36"- TRANSCO 54.18%, TENNESSEE GAS PIPELINE COMPANY 27.07%, COLUMBIA GULF TRANSMISSION COMPANY 16%, NORTHERN NATURAL GAS COMPANY 2.75%

(c) Concept: DesignationIdentificationOfLineOrGroupOfLines

SUMMARY OF JOINTLY OWNED TRANSMISSION LINES NOT OPERATED BY TRANSCO-LOUISIANA ONSHORE AND STATE WATERS

 

1) 1.30 MILES OF 4” – TRANSCO 44.55% TEXAS GAS TRANSMISSION COMPANY 55.45%

(d) Concept: DesignationIdentificationOfLineOrGroupOfLines

SUMMARY OF JOINTLY OWNED TRANSMISSION LINES OPERATED BY TRANSCO-LOUISIANA ONSHORE AND STATE WATERS

 

1) 0.20 MILES OF 24" - TRANSCO 16.67%, FLORIDA GAS TRANSMISSION COMPANY 16.67%, SEA ROBIN PIPELINE COMPANY 66.66%

 

2) 13.90 MILES OF 24" - TRANSCO 38.124%, GULF SOUTH 61.876%

 

3) 12.43 MILES OF 24"- TRANSCO 16.6667%, SEA ROBIN PIPELINE COMPANY 66.6667%, FLORIDA GAS TRANSMISSION COMPANY 16.6666%

 

4) 20.27 MILES OF 36" - TRANSCO 66.2236%, FLORIDA GAS TRANSMISSION COMPANY 10.6686%, TENNESSEE GAS PIPELINE COMPANY 23.1078%

(e) Concept: DesignationIdentificationOfLineOrGroupOfLines

SUMMARY OF JOINTLY OWNED TRANSMISSION LINES OPERATED BY TRANSCO-MISSISSIPPI ONSHORE AND STATE WATERS

 

1) 1.20 MILES OF 3" - TRANSCO 50%, FLORIDA GAS TRANSMISSION COMPANY 50%

 

2) 6.10 MILES OF 6" - TRANSCO 50%, FLORIDA GAS TRANSMISSION COMPANY 50%

 

3) 1.04 MILES OF 6"- TRANSCO 11%, FLORIDA GAS TRANSMISSION COMPANY 89%

 

4) 0.50 MILES OF 6" - TRANSCO 55.85938%, FLORIDA GAS TRANSMISSION COMPANY 44.14062%

 

5) 10.66 MILES OF 26”-TRANSCO 57.702500%, FLORIDA GAS TRANSMISSION COMPANY 42.297500%

(f) Concept: DesignationIdentificationOfLineOrGroupOfLines

SUMMARY OF JOINTLY OWNED TRANSMISSION LINES OPERATED BY TRANSCO-ALABAMA ONSHORE AND STATE WATERS

 

1) 123.43 MILES OF 30"- TRANSCO 80.21%, FLORIDA GAS TRANSMISSION COMPANY 19.79%

 

2) 0.24 MILES OF 16” –TRANSCO 62.78%, FLORIDA GAS TRANSMISSION COMPANY 37.22%

 

3) 4.73 MILES OF 26” – TRANSCO 57.7025%, FLORIDA GAS TRANSMISSION COMPANY 42.2975%

(g) Concept: DesignationIdentificationOfLineOrGroupOfLines

SUMMARY OF JOINTLY OWNED TRANSMISSION LINES OPERATED BY TRANSCO-GEORGIA ONSHORE AND STATE WATERS

 

1) 47.8 MILES OF 20" - TRANSCO 50%, DOGWOOD ENTERPRISE HOLDINGS, INC 50%

 

2) 7.9 MILES OF 30" - TRANSCO 50%, DOGWOOD ENTERPRISE HOLDINGS, INC 50%

 

3) 45.21 MILES OF 24"- TRANSCO 50%, DOGWOOD ENTERPRISE HOLDINGS, INC 50%

 

4) 5.2. MILES OF 16" – TRANSCO 50%, DOGWOOD ENTERPRISE HOLDINGS, INC 50%

(h) Concept: DesignationIdentificationOfLineOrGroupOfLines

1) 55.8 MILES OF 30” – TRANSCO 41.18%, MEADE PIPELINE CO 58.82%

 

2) 121 MILES OF 42” – TRANSCO 70.59%, MEADE PIPELINE CO 29.41%

(i) Concept: DesignationIdentificationOfLineOrGroupOfLines

SUMMARY OF JOINTLY OWNED TRANSMISSION LINES OPERATED BY TRANSCO-FEDERAL WATERS

 

1) 15.10 MILES OF 20”- TRANSCO 82.94%, NORTHERN NATURAL GAS COMPANY 10.08%, ANR PIPELINE COMPANY 6.98%

 

2) 1.31 MILES OF 12"- TRANSCO 82.94%, ANR PIPELINE COMPANY 6.98%, NORTHERN NATURAL GAS COMPANY 10.08%

 

3) 2.30 MILES OF 12"- TRANSCO 35%, TEXAS GAS TRANSMISSION 15%, NORTHERN NATURAL GAS COMPANY 50%

 

4) 5.42 MILES OF 20"- TRANSCO 38.6980%, COLUMBIA GULF TRANSMISSION 10.2440%, TEXAS GAS TRANSMISSION 9.8780%, TC OFFSHORE 1.424%, NORTHERN NATURAL GAS COMPANY 39.7560%

 

5) 0.30 MILES OF 20"- TRANSCO 35%, NORTHERN NATURAL GAS COMPANY 50%, TEXAS GAS TRANSMISSION 15%

 

6) 3.13 MILES OF 20"- TRANSCO 39.829%, TEXAS GAS TRANSMISSION 8.312%, NORTHERN NATURAL GAS COMPANY 36.624%, TC OFFSHORE 1.859%, COLUMBIA GULF TRANSMISSION 13.376%

 

7) 4.75 MILES OF 16"- TRANSCO 45.83%, COLUMBIA GULF TRANSMISSION 30%, NORTHERN NATURAL GAS COMPANY 20%, TC OFFSHORE 4.17%

 

8) 13.70 MILES OF 16" -TRANSCO 45.83%, COLUMBIA GULF TRANSMISSION 30%, NORTHERN NATURAL GAS COMPANY 20%, TC OFFSHORE 4.17%

 

9) 1.08 MILES OF 20”- TRANSCO 39.165%, TC OFFSHORE 30.33%, GULF SOUTH 27.84%, TENNESSEE 2.665%

 

10) 0.54 MILES OF 12”- TRANSCO 69.217%, TC OFFSHORE 6.659%, GULF SOUTH 20.988%, TENNESSEE 3.136%

(j) Concept: DesignationIdentificationOfLineOrGroupOfLines

SUMMARY OF JOINTLY OWNED TRANSMISSION LINES NOT OPERATED BY TRANSCO-FEDERAL WATERS

 

1) 3.08 MILES OF 12"- TRANSCO 16.67%, GULF SOUTH 44.17%, TC OFFSHORE 39.16%

 

2) 1.64 MILES OF 12”- TRANSCO 33.33%, ENTERPRISE 33.33%, GULF SOUTH 33.34%

 

3) 0.65 MILES OF 16” –TRANSCO 15.07%, ANR PIPELINE COMPANY 22.23%, TEXAS GAS TRANSMISSION 47.64%, APACHE 15.06%

 

4) 3.37 MILES OF 20”- TRANSCO 50%, ENTERPRISE 25%, TEXAS EASTERN TRANSMISSION CORPORATION 25%

 

5) 6.11 MILES OF 20”- TRANSCO 57%, TEXAS EASTERN TRANSMISSION CORPORATION 24.83%, ENTERPRISE 14.17, TC OFFSHORE 4%

 

6) 0.88 MILES OF 20”- TRANSCO 48.40%, TEXAS EASTERN TRANSMISSION CORPORATION 29.8%, ENTERPRISE 17%, TC OFFSHORE 4.8%

 

7) 20.48 MILES OF 12"- TRANSCO 43.29%, TEXAS EASTERN TRANSMISSION CORPORATION 43.129%, ENTERPRISE 13.581%

 

8) 12.09 MILES OF 16"- TRANSCO 60%, TEXAS EASTERN TRANSMISSION CORPORATION 20%, NORTHERN NATURAL GAS COMPANY 20%


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Transmission System Peak Deliveries
  1. Report below the total transmission system deliveries of gas (in Dth), excluding deliveries to storage, for the period of system peak deliveries indicated below, during the 12 months embracing the heating season overlapping the year's end for which this report is submitted. The season's peak normally will be reached before the due date of this report, April 30, which permits inclusion of the peak information required on this page. Add rows as necessary to report all data. Number additional rows 6.01, 6.02, etc.
Line No.
Description
(a)
Dth of Gas Delivered to Interstate Pipelines
(b)
Dth of Gas Delivered to Others
(c)
Total (b) + (c)
(d)
SECTION A: SINGLE DAY PEAK DELIVERIES
1
Date(s):
2
Volumes of Gas Transported
3
NoNoticeTransportationVolumesOfGasTransported
No-Notice Transportation
4,174,644
9,890,871
14,065,515
4
OtherFirmTransportationVolumesOfGasTransported
Other Firm Transportation
5
InterruptibleTransportationVolumesOfGasTransported
Interruptible Transportation
246,683
345,551
592,234
6
Other (Specify)
6.1
(a)
Other (Describe) (footnote details)
452,380
354,792
97,588
7
TOTAL
4,873,707
9,881,630
14,755,337
8
Volumes of gas Withdrawn form Storage under Storage Contract
9
NoNoticeStorageVolumesOfGasWithdrawnFromStorageUnderStorageContract
No-Notice Storage
738
1,073,125
1,073,863
10
OtherFirmStorageVolumesOfGasWithdrawnFromStorageUnderStorageContract
Other Firm Storage
11
InterruptibleStorageVolumesOfGasWithdrawnFromStorageUnderStorageContract
Interruptible Storage
12
Other (Specify)
12.1
Other (Describe) (footnote details)
13
TOTAL
738
1,073,125
1,073,863
14
Other Operational Activities
15
GasWithdrawnFromStorageForSystemOperationsOtherOperationalActivities
Gas Withdrawn from Storage for System Operations
1,096,728
1,096,728
16
ReductionInLinePackOtherOperationalActivities
Reduction in Line Pack
74,972
74,972
17
Other (Specify)
17.1
Other (FUEL)
183,229
183,229
18
TOTAL
1,204,985
1,204,985
19
SECTION B: CONSECUTIVE THREE_DAY PEAK DELIVERIES
20
Date(s):
22
NoNoticeTransportationVolumesOfGasTransported
No-Notice Transportation
12,494,462
28,760,050
41,254,512
23
OtherFirmTransportationVolumesOfGasTransported
Other Firm Transportation
24
InterruptibleTransportationVolumesOfGasTransported
Interruptible Transportation
731,928
1,016,653
1,748,581
25
Other (Specify)
25.1
(b)
Other (Describe) (footnote details)
1,180,959
1,023,699
157,260
26
TOTAL
14,407,349
28,753,004
43,160,353
27
Volumes of gas Withdrawn form Storage under Storage Contract
28
NoNoticeStorageVolumesOfGasWithdrawnFromStorageUnderStorageContract
No-Notice Storage
3,403
3,024,411
3,027,814
29
OtherFirmStorageVolumesOfGasWithdrawnFromStorageUnderStorageContract
Other Firm Storage
30
InterruptibleStorageVolumesOfGasWithdrawnFromStorageUnderStorageContract
Interruptible Storage
31
Other (Specify)
31.1
Other (Describe) (footnote details)
32
TOTAL
3,403
3,024,411
3,027,814
33
Other Operational Activities
34
GasWithdrawnFromStorageForSystemOperationsOtherOperationalActivities
Gas Withdrawn from Storage for System Operations
2,484,578
2,484,578
35
ReductionInLinePackOtherOperationalActivities
Reduction in Line Pack
76,303
76,303
36
Other (Specify)
36.1
Other (FUEL)
536,049
536,049
37
TOTAL
3,096,930
3,096,930


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionOfTransmissionSystemDeliveriesOfGasGasTransported

 

THOSE TRANSACTIONS THAT FLOW ON RATE SCHEDULES OTHER THAN FT, IT, OR BUNDLED STORAGE ARE CATEGORIZED AS OTHER.

(b) Concept: DescriptionOfTransmissionSystemDeliveriesOfGasGasTransported

 

THOSE TRANSACTIONS THAT FLOW ON RATE SCHEDULES OTHER THAN FT, IT, OR BUNDLED STORAGE ARE CATEGORIZED AS OTHER.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Auxiliary Peaking Facilities
  1. Report below auxiliary facilities of the respondent for meeting seasonal peak demands on the respondent's system, such as underground storage projects, liquefied petroleum gas installations, gas liquefaction plants, oil gas sets, etc.
  2. For column (c), for underground storage projects, report the delivery capacity on February 1 of the heating season overlapping the year-end for which this report is submitted. For other facilities, report the rated maximum daily delivery capacities.
  3. For column (d), include or exclude (as appropriate) the cost of any plant used jointly with another facility on the basis of predominant use, unless the auxiliary peaking facility is a separate plant as contemplated by general instruction 12 of the Uniform System of Accounts.
Line No.
LocationOrNameOfFacility
Location of Facility
(a)
AuxiliaryPeakingFacilitiesTypeOfFacility
Type of Facility
(b)
AuxiliaryPeakingFacilitiesMaximumDailyDeliveryCapacityOfFacility
Maximum Daily Delivery Capacity of Facility Dth
(c)
AuxiliaryPeakingFacilitiesCostOfFacility
Cost of Facility (in dollars)
(d)
AuxiliaryPeakingFacilitiesIndicatorIfFacilityOperatedOnDayOfHighestTransmissionPeakDelivery
Was Facility Operated on Day of Highest Transmission Peak Delivery?
(e)
1
HACKENSACK MEADOWS
LNG STORAGE
377,775
74,747,764
(e)
True
2
NEW JERSEY
3
LNG FACILITY
4
ST. LANDRY PARISH
UNDERGROUND STORAGE
817,404
131,399,492
(f)
True
5
LOUISIANA
6
WASHINGTON STORAGE FIELD
7
COVINGTON COUNTY
UNDERGROUND STORAGE
(a)
1,232,400
127,040,746
(g)
True
8
MISSISSIPPI
9
EMINENCE STORAGE FIELD
10
POTTER,CLINTON & CAMERON COUNTIES
UNDERGROUND STORAGE
(b)
323,442
61,960,247
(h)
True
11
PENNSYLVANIA
12
LEIDY-TAMARACK STORAGE FIELD
13
POTTER & CAMERON COUNTIES
UNDERGROUND STORAGE
(c)
248,400
58,434,835
(i)
False
14
PENNSYLVANIA
15
WHARTON STORAGE FIELD
16


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: AuxiliaryPeakingFacilitiesMaximumDailyDeliveryCapacityOfFacility

 

TOTAL MAXIMUM DAILY DELIVERY CAPACITY FOR CAVERNS 5, 6, AND 7 IS 1,232,400. CAVERN 5 IS TEMPORARILY OUT OF SERVICE.

(b) Concept: AuxiliaryPeakingFacilitiesMaximumDailyDeliveryCapacityOfFacility

 

TOTAL MAXIMUM DAILY DELIVERY CAPACITY FOR THE FIELD IS 1,293,768. TRANSCO’S 25 PERCENT INTEREST IS 323,442.

(c) Concept: AuxiliaryPeakingFacilitiesMaximumDailyDeliveryCapacityOfFacility

 

TOTAL MAXIMUM DAILY DELIVERY CAPACITY FOR THE FIELD IS 310,500. TRANSCO’S 80 PERCENT INTEREST IS 248,400. WHARTON STORAGE FIELD WAS OUT OF SERVICE DURING THE REPORTING PERIOD.

(d) Concept: AuxiliaryPeakingFacilitiesCostOfFacility

 

EXCLUDES GAS STORED UNDERGROUND-NONCURRENT STORED IN LEIDY, WHARTON, EMINENCE, AND WASHINGTON FIELDS IN THE AMOUNT OF $76,516,841.

(e) Concept: AuxiliaryPeakingFacilitiesIndicatorIfFacilityOperatedOnDayOfHighestTransmissionPeakDelivery
Original value: Y
(f) Concept: AuxiliaryPeakingFacilitiesIndicatorIfFacilityOperatedOnDayOfHighestTransmissionPeakDelivery
Original value: Y
(g) Concept: AuxiliaryPeakingFacilitiesIndicatorIfFacilityOperatedOnDayOfHighestTransmissionPeakDelivery
Original value: Y
(h) Concept: AuxiliaryPeakingFacilitiesIndicatorIfFacilityOperatedOnDayOfHighestTransmissionPeakDelivery
Original value: Y
(i) Concept: AuxiliaryPeakingFacilitiesIndicatorIfFacilityOperatedOnDayOfHighestTransmissionPeakDelivery
Original value: N

Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Gas Account - Natural Gas
  1. The purpose of this schedule is to account for the quantity of natural gas received and delivered by the respondent.
  2. Natural gas means either natural gas unmixed or any mixture of natural and manufactured gas.
  3. Enter in column (c) the year to date Dth as reported in the schedules indicated for the items of receipts and deliveries.
  4. Enter in column (d) the respective quarter’s Dth as reported in the schedules indicated for the items of receipts and deliveries.
  5. Indicate in a footnote the quantities of bundled sales and transportation gas and specify the line on which such quantities are listed.
  6. If the respondent operates two or more systems which are not interconnected, submit separate pages for this purpose.
  7. Indicate by footnote the quantities of gas not subject to Commission regulation which did not incur FERC regulatory costs by showing (1) the local distribution volumes another jurisdictional pipeline delivered to the local distribution company portion of the reporting pipeline (2) the quantities that the reporting pipeline transported or sold through its local distribution facilities or intrastate facilities and which the reporting pipeline received through gathering facilities or intrastate facilities, but not through any of the interstate portion of the reporting pipeline, and (3) the gathering line quantities that were not destined for interstate market or that were not transported through any interstate portion of the reporting pipeline.
  8. Indicate in a footnote the specific gas purchase expense account(s) and related to which the aggregate volumes reported on line No. 3 relate.
  9. Indicate in a footnote (1) the system supply quantities of gas that are stored by the reporting pipeline, during the reporting year and also reported as sales,transportation and compression volumes by the reporting pipeline during the same reporting year, (2) the system supply quantities of gas that are stored by the reporting pipeline during the reporting year which the reporting pipeline intends to sell or transport in a future reporting year, and (3) contract storage quantities.
  10. Also indicate the volumes of pipeline production field sales that are included in both the company's total sales figure and the company;s total transportation figure. Add additional information as necessary to the footnotes.
Line No.
Item
(a)
Ref. Page No. of (FERC Form Nos. 2/2-A)
(b)
Total Amount of Dth Year to Date
(c)
Current Three Months Ended Amount of Dth Quarterly Only
(d)
1
NameOfSystem
Name of System
2
QuantityOfNaturalGasReceivedByUtilityAbstract
GAS RECEIVED
3
QuantityOfNaturalGasReceivedByUtilityGasPurchases
Gas Purchases (Accounts 800-805)
(a)
55,797,999
(h)
12,577,875
4
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForGathering
Gas of Others Received for Gathering (Account 489.1)
303
11,734,451
2,444,539
5
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForTransmission
Gas of Others Received for Transmission (Account 489.2)
305
5,525,098,298
1,273,149,212
6
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForDistribution
Gas of Others Received for Distribution (Account 489.3)
301
7
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForContractStorage
Gas of Others Received for Contract Storage (Account 489.4)
307
145,179,267
43,612,765
8
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForProductionExtractionProcessing
Gas of Others Received for Production/Extraction/Processing (Account 490 and 491)
9
QuantityOfNaturalGasReceivedByUtilityExchangedGasReceivedFromOthers
Exchanged Gas Received from Others (Account 806)
328
8,781,337
1,127,100
10
QuantityOfNaturalGasReceivedByUtilityGasReceivedAsImbalances
Gas Received as Imbalances (Account 806)
328
32,438,876
6,375,024
11
QuantityOfNaturalGasReceivedByUtilityReceiptsOfUtilitysGasTransportedByOthers
Receipts of Respondent's Gas Transported by Others (Account 858)
332
12
QuantityOfNaturalGasReceivedByUtilityOtherGasWithdrawnFromStorage
Other Gas Withdrawn from Storage (Explain)
(b)
1,096,361
(i)
2,791,137
13
QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsCompressorStationFuel
Gas Received from Shippers as Compressor Station Fuel
32,610,212
9,030,721
14
QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsLostAndUnaccountedFor
Gas Received from Shippers as Lost and Unaccounted for
(c)
13,359,366
(j)
3,643,975
15
QuantityOfNaturalGasReceivedByUtilityOther
Other Receipts (Specify) (footnote details)
(d)
1,619,850
(k)
68,652
15.1
QuantityOfNaturalGasReceivedByUtilityOther
Other Receipts (Specify) (footnote details)
16
QuantityOfNaturalGasReceivedByUtility
Total Receipts (Total of lines 3 thru 15)
(e)
5,827,716,017
1,354,821,000
17
QuantityOfNaturalGasDeliveredByUtilityAbstract
GAS DELIVERED
18
QuantityOfNaturalGasDeliveredByUtilityGasSales
Gas Sales (Accounts 480-484)
19
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasGatheredForOthers
Deliveries of Gas Gathered for Others (Account 489.1)
303
11,734,451
2,444,539
20
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasTransportedForOthers
Deliveries of Gas Transported for Others (Account 489.2)
305
5,525,098,298
1,273,149,212
21
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasDistributedForOthers
Deliveries of Gas Distributed for Others (Account 489.3)
301
22
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfContractStorageGas
Deliveries of Contract Storage Gas (Account 489.4)
307
134,107,591
20,782,257
23
QuantityOfNaturalGasDeliveredByUtilityGasOfOthersDeliveredForProductionExtractionProcessing
Gas of Others Delivered for Production/Extraction/Processing (Account 490 and 491)
24
QuantityOfNaturalGasDeliveredByUtilityExchangeGasDeliveredToOthers
Exchange Gas Delivered to Others (Account 806)
328
8,781,337
1,127,100
25
QuantityOfNaturalGasDeliveredByUtilityGasDeliveredAsImbalances
Gas Delivered as Imbalances (Account 806)
328
31,455,185
6,538,373
26
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasToOthersForTransportation
Deliveries of Gas to Others for Transportation (Account 858)
332
27
QuantityOfNaturalGasDeliveredByUtilityOtherGasDeliveredToStorage
Other Gas Delivered to Storage (Explain)
(f)
10,433,740
(l)
6,226,334
28
QuantityOfNaturalGasDeliveredByUtilityGasUsedForCompressorStationFuel
Gas Used for Compressor Station Fuel
509
32,459,315
7,859,378
29
GasUsedForOtherDeliveriesAndGasUsedForOtherOperations
Other Deliveries and Gas Used for Other Operations
(g)
60,084,472
(m)
33,183,211
29.1
GasUsedForOtherDeliveriesAndGasUsedForOtherOperations
Other Deliveries and Gas Used for Other Operations
30
QuantityOfNaturalGasDeliveredByUtility
Total Deliveries (Total of lines 18 thru 29)
5,814,154,389
1,351,310,404
31
GasLossesAndGasUnaccountedForGasAccountAbstract
GAS LOSSES AND GAS UNACCOUNTED FOR
32
GasAccountGasLossesAndGasUnaccountedForGasAccount
Gas Losses and Gas Unaccounted For
13,561,628
3,510,596
33
DeliveriesGasLossesAndUnaccountedForGasAccountAbstract
TOTALS
34
DeliveriesGasLossesAndUnaccountedForGasAccount
Total Deliveries, Gas Losses & Unaccounted For (Total of lines 30 and 32)
5,827,716,017
1,354,821,000


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: QuantityOfNaturalGasReceivedByUtilityGasPurchases

 

FOOTNOTE TO INSTRUCTION 8:

 

ALL VOLUMES FOR GAS PURCHASES ARE RECORDED TO ACCOUNT 803.

 

LINE 3, COLUMN C, INCLUDES THE FOLLOWING VOLUMES:

 

CASH-OUT PURCHASES

36,747,999

DTs

SYSTEM MANAGEMENT GAS PURCHASES

19,050,000

DTs

 

55,797,999

DTs

(b) Concept: QuantityOfNaturalGasReceivedByUtilityOtherGasWithdrawnFromStorage

 

INCLUDES THE FOLLOWING VOLUMES WITHDRAWN FROM STORAGE:

 

GSS

 

1,748,969

LSS

 

(316,733)

SS-2

 

1,053,460

S-2

 

(1,132,888)

WSS

 

(12,012,380)

LNG

 

1,682,543

LGS

 

0

EMINENCE

 

10,331,273

LGA

 

(257,883)

TOTAL

 

1,096,361

(c) Concept: QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsLostAndUnaccountedFor

 

FIRST QUARTER:

 

30.28% OF THE TOTAL GAS RECEIVED FROM SHIPPERS AS FUEL REIMBURSEMENT WAS CALCULATED TO BE RECEIVED AS LOST AND UNACCOUNTED FOR. THIS PERCENTAGE WAS DERIVED FROM THE DATA UNDERLYING THE 2018 FUEL TRACKER FILING.

 

SECOND QUARTER

 

28.75% OF THE TOTAL GAS RECEIVED FROM SHIPPERS AS FUEL REIMBURSEMENT WAS CALCULATED TO BE

RECEIVED AS LOST AND UNACCOUNTED FOR. THIS PERCENTAGE WAS DERIVED FROM THE DATA

UNDERLYING THE 2018 FUEL TRACKER FILING.

 

THIRD QUARTER

 

28.75% OF THE TOTAL GAS RECEIVED FROM SHIPPERS AS FUEL REIMBURSEMENT WAS CALCULATED TO BE

RECEIVED AS LOST AND UNACCOUNTED FOR. THIS PERCENTAGE WAS DERIVED FROM THE DATA

UNDERLYING THE 2018 FUELTRACKER FILING.

 

FOURTH QUARTER

 

28.75% OF THE TOTAL GAS RECEIVED FROM SHIPPERS AS FUEL REIMBURSEMENT WAS CALCULATED TO BE

RECEIVED AS LOST AND UNACCOUNTED FOR. THIS PERCENTAGE WAS DERIVED FROM THE DATA

UNDERLYING THE 2018 FUELTRACKER FILING.

(d) Concept: QuantityOfNaturalGasReceivedByUtilityOther

 

INCLUDES DECREASE IN LINE PACK OF:

 

1,619,850 DTs

(e) Concept: QuantityOfNaturalGasReceivedByUtility

 

FOOTNOTE TO INSTRUCTION 5:

 

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC DOES NOT BUNDLE SALES AND TRANSPORTATION SERVICES.

 

FOOTNOTE TO INSTRUCTION 7:

 

ALL QUANTITIES OF GAS WERE SUBJECT TO COMMISSION REGULATION.

 

FOOTNOTE TO INSTRUCTION 9 (3):

 

CONTRACT STORAGE QUANTITIES ARE AS FOLLOWS:

 

RATE SCHEDULE

DTs

RATE SCHEDULE

DTs

ESS

6,689,005

S-2

9,274,778

GSS

52,046,984

SS-2

7,480,571

LGA

229,353

WSS

45,863,727

LNG

1,833,419

LSS

11,134,632

LGS

0

 

 

 

FOOTNOTE TO INSTRUCTION 10:

 

THERE ARE NO VOLUMES OF PIPELINE PRODUCTION FIELD SALES INCLUDED IN THE TOTAL SALES VOLUMES OR THE TOTAL TRANSPORTATION VOLUMES.

(f) Concept: QuantityOfNaturalGasDeliveredByUtilityOtherGasDeliveredToStorage

 

INCLUDES THE FOLLOWING VOLUMES INJECTED INTO STORAGE:

 

GSS

 

7,837,275

LSS

 

1,554,966

SS-2

 

807,235

S-2

 

(1,914,670)

WSS

 

(7,437,621)

LGA

 

(547,142)

LGS

 

0

EMINENCE

 

8,025,595

LNG

 

2,108,102

TOTAL

 

10,433,740

 

 

 

 

 

 

 

 

 

 

 

(g) Concept: GasUsedForOtherDeliveriesAndGasUsedForOtherOperations

 

LINE INCLUDES THE FOLLOWING:

 

CASH-OUT SALES

 

44,583,547

INCREASE IN LINE PACK

 

3,028,038

CATHODIC PROTECTION

 

12,784

PURGING AND TESTING

 

1,388,427

CONTRACT STORAGE RECEIVED

 

145,179,267

CONTRACT STORAGE DELIVERED

(134,107,591)

TOTAL

 

60,084,472

(h) Concept: QuantityOfNaturalGasReceivedByUtilityGasPurchases

 

FOOTNOTE TO INSTRUCTION 8:

 

ALL VOLUMES FOR GAS PURCHASES ARE RECORDED TO ACCOUNT 803.

 

LINE 3, COLUMN D INCLUDES THE FOLLOWING VOLUMES:

 

CASH-OUT PURCHASES

11,027,875

DTs

SYSTEM MANAGEMENT GAS PURCHASES

1,550,000

DTs

 

12,577,875

DTs

(i) Concept: QuantityOfNaturalGasReceivedByUtilityOtherGasWithdrawnFromStorage

 

INCLUDES THE FOLLOWING VOLUMES WITHDRAWN FROM STORAGE:

 

GSS

 

477,571

LSS

 

(1,682,440)

SS-2

 

1,882,420

S2

 

(158,548)

WSS

 

(3,091,866)

LNG

 

379,483

LGS

 

0

EMINENCE

 

4,989,265

LGA

 

(4,748)

TOTAL

 

2,791,137

(j) Concept: QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsLostAndUnaccountedFor

 

IN THE FOURTH QUARTER, 28.75% OF THE TOTAL GAS RECEIVED FROM SHIPPERS AS FUEL REIMBURSEMENT WAS CALCULATED TO BE RECEIVED AS LOST AND UNACCOUNTED FOR. THIS PERCENTAGE WAS DERIVED FROM THE DATA UNDERLYING THE 2018 FUEL TRACKER FILING.

(k) Concept: QuantityOfNaturalGasReceivedByUtilityOther

 

INCLUDES DECREASE IN LINE PACK OF:

 

68,652 DTs

 

 

 

 

 

 

 

 

 

(l) Concept: QuantityOfNaturalGasDeliveredByUtilityOtherGasDeliveredToStorage

 

INCLUDES THE FOLLOWING VOLUMES INJECTED INTO STORAGE:

 

GSS

 

5,269,414

LSS

 

1,937,254

SS-2

 

22,309

S-2

 

(1,306,577)

WSS

 

(2,627,163)

LGA

 

(17,613)

LGS

 

0

EMINENCE

 

2,230,954

LNG

 

717,756

TOTAL

 

6.226,334

(m) Concept: GasUsedForOtherDeliveriesAndGasUsedForOtherOperations

 

LINE INCLUDES THE FOLLOWING:

 

CASH-OUT SALES

 

9,041,823

INCREASE IN LINE PACK

 

1,168,793

CATHODIC PROTECTION

 

3,166

PURGING AND TESTING

 

138,921

CONTRACT STORAGE RECEIVED

 

43,612,765

CONTRACT STORAGE DELIVERED

 

(20,782,257)

TOTAL

 

33,183,211

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

THE FOLLOWING VOLUMES HAVE BEEN DUPLICATED IN LINE 30, PAGE 520,OR ARE NOT SUBJECT TO ACA

SURCHARGES:

 

  1. GAS SALES (ACCOUNT 480-484), LINE 18, PAGE 520, IN THE AMOUNT OF 0 DT’S.

 

  1. DELIVERIES OF CONTRACT STORAGE GAS (ACCOUNT 489.4) LINE 22, PAGE 520, IN THE AMOUNT OF 134,107,591 DT’S.

 

  1. OTHER GAS DELIVERED TO STORAGE, LINE 27, PAGE 520, IN THE AMOUNT OF 10,433,740 DT’S.

 

  1. OTHER DELIVERIES, LINE 29, PAGE 520, IN THE AMOUNT OF 60,084,472 DT’S.

 

  1. FEEDERS OF 1,227,303,465 DT’S ARE INCLUDED IN LINE 20, PAGE 520.

 

  1. DELIVERIES TO WASHINGTON STORAGE OF 37,864,036 DT’S ARE INCLUDED IN LINE 20, PAGE 520.

 

  1. EXCHANGE GAS DELIVERED TO OTHERS OF 8,781,337 DT’S ARE INCLUDED IN LINE 24, PAGE 520.

 

  1. GAS DELIVERED AS IMBALANCES OF 31,455,185 DT’S ARE INCLUDED IN LINE 25, PAGE 520.

 

  1. GAS USED FOR COMPRESSOR STATION FUEL OF 32,459,315 DT’S ARE INCLUDED IN LINE 28, PAGE 520.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Shipper Supplied Gas for the Current Quarter
  1. Report monthly (1) shipper supplied gas for the current quarter and gas consumed in pipeline operations, (2) the disposition of any excess, the accounting recognition given to such disposition and the specific account(s) charged or credited, and (3) the source of gas used to meet any deficiency, the accounting recognition given to the gas used to meet the deficiency, including the accounting basis of the gas and the specific account(s) charged or credited.
  2. On lines 7, 14, 22 and 30 report only the dekatherms of gas provided by shippers under tariff terms and conditions for gathering , production/ extraction/processing, transmission, distribution and storage service and the use of that gas for compressor fuel, other operational purposes and lost and unaccounted for. The dekatherms must be broken out by functional categories on Lines 2-6, 9-13, 16-21 and 24-29. The dekatherms must be reported in column (d) unless the company has discounted or negotiated rates which should be reported in columns (b) and (c).
  3. On lines 7, 14, 22 and 30 report only the dollar amounts of gas provided by shippers under tariff terms and conditions for gathering, production/ extraction/processing, transmission, distribution and storage service and the use of that gas for compressor fuel, other operational purposes and lost and unaccounted for. The dollar amounts must be broken out by functional categories on Lines 2-6, 9-13, 16-21 and 23-29. The dollar amounts must be reported in column (h) unless the company has discounted or negotiated rates which should be reported in columns (f) and (g). The accounting should disclose the account(s) debited and credited in columns (m) and (n).
  4. Indicate in a footnote the basis for valuing the gas reported in Columns (f), (g) and (h).
  5. Report in columns (j), (k) and (l) the amount of fuel waived, discounted or reduced as part of a negotiated rate agreement.
  6. On lines 32-37 report the dekatherms and dollar value of the excess or deficiency in shipper supplied gas broken out by functional category and whether recourse rate, discounted or negotiated rate.
  7. On lines 39 through 51 report the dekatherms, the dollar amount and the account(s) credited in Column (o) for the dispositions of gas listed in column (a).
  8. On lines 53 through 65 report the dekatherms, the dollar amount and the account(s) debited in Column (n) for the sources of gas reported in column (a).
  9. On lines 66 and 67, report forwardhaul and backhaul volume in Dths of throughput.
  10. Where appropriate, provide a full explanation of the allocation process used in reported numbers in a footnote.
Month 1
Amount Collected (Dollars) Volume (in Dth) Not Collected
Line No.
Item
(a)
Discounted rate Dth
(b)
Negotiated Rate Dth
(c)
Recourse Rate Dth
(d)
Total Dth
(e)
Discounted Rate, Amount
(f)
Negotiated Rate Amount
(g)
Recourse rate Amount
(h)
Total Amount
(i)
Waived Dth
(j)
Discounted Dth
(k)
Negotiated Dth
(l)
Total Dth
(m)
Account(s) Debited
(n)
Account(s) Credited
(o)
1
SHIPPER SUPPLIED GAS (LINES 13 AND 14 , PAGE 520)
2
Gathering
3
Production/Extraction/Processing
4
Transmission
19,421
18,804
3,643,949
3,682,174
57,094
55,286
10,713,212
10,825,592
5
Distribution
6
Storage
242,466
242,466
712,850
712,850
7
Total Shipper Supplied Gas
19,421
18,804
3,886,415
3,924,640
57,094
55,286
11,426,062
(b)
11,538,442
LESS GAS USED FOR COMPRESSOR STATION FUEL (LINE 28, PAGE 520)
9
Gathering
10
Production/Extraction/Processing
11
Transmission
10,764
10,423
2,019,760
(a)
2,040,947
31,646
30,644
5,938,094
6,000,384
12
Distribution
13
Storage
277,563
277,563
816,035
816,035
14
Total gas used in compressors
10,764
10,423
2,297,323
2,318,510
31,646
30,644
6,754,129
6,816,419
15
LESS GAS USED FOR OTHER DELIVERIES AND GAS USED FOR OTHER OPERATIONS (LINE 29, PAGE 520) (Footnote)
16
Gathering
17
Production/Extraction/Processing
18
Transmission
91
88
17,031
17,210
266
257
49,844
50,367
19
Distribution
20
Storage
21
Other Deliveries (specify) (footnote details)
22
Total Gas Used For Other Deliveries And Gas Used For Other Operations
91
88
17,031
17,210
266
257
49,844
50,367
23
LESS GAS LOST AND UNACCOUNTED FOR (LINE 32, PAGE 520)
24
Gathering
25
Production/Extraction/Processing
26
Transmission
3,448
3,338
646,919
653,705
10,136
9,815
1,901,942
1,921,893
27
Distribution
28
Storage
29
Other Deliveries (specify) (footnote details)
30
Total Gas Lost And Unaccounted For
3,448
3,338
646,919
653,705
10,136
9,815
1,901,942
1,921,893
30.1
NET EXCESS OR (DEFICIENCY)
31
Other Losses
32
Gathering
33
Production/Extraction/Processing
34
Transmission
5,118
4,955
960,239
970,312
15,046
14,570
2,823,332
2,852,948
35
Distribution
36
Storage
35,097
35,097
103,185
103,185
37
Total Net Excess Or (Deficiency)
5,118
4,955
925,142
935,215
15,046
14,570
2,720,147
2,749,763
38
DISPOSITION OF EXCESS GAS:
39
Gas sold to others
40
Gas used to meet imbalances
5,118
4,955
925,142
935,215
15,046
14,570
2,720,147
2,749,763
41
Gas added to system gas
42
Gas returned to shippers
43.1
43.2
43.3
43.4
43.5
43.6
43.7
43.8
51
Total Disposition Of Excess Gas
5,118
4,955
925,142
935,215
15,046
14,570
2,720,147
2,749,763
52
GAS ACQUIRED TO MEET DEFICIENCY:
53
System gas
54
Purchased gas
65
Total Gas Acquired To Meet Deficiency

SEPARATION OF FORWARDHAUL AND BACKHAUL THROUGHPUT
Line No.
Item
(a)
Quarter
Dth (b)
66
Forwardhaul Volume in Dths for the Quarter
1,272,720,133
67
Backhaul Volume in Dths for the Quarter
2,873,618
68
TOTAL (Lines 66 and 67)
1,275,593,751


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: GasUsedForCompressorStationFuelTransmission

 

PAGE 521, LINE 11, COLUMN E

 

THE FOLLOWING APPLIES TO ALL VOLUMES, FOR ALL MONTHS, IN LINES 11, 18, 26, 34, 40, AND 56:

 

VOLUMES WERE ALLOCATED PRORATA TO “DISCOUNTED RATE”, “NEGOTIATED RATE”, AND “RECOURSE RATE” BASED ON THE ACTUAL VOLUMES PRESENTED ON LINE 4.

(b) Concept: AmountCollectedShipperSuppliedGas

 

PAGE 521, LINE 7, COLUMN i

 

BASIS FOR VALUATION OF ALL GAS:

 

GAS IS VALUED MONTHLY AT A NGW INDEX PRICE WHEN THERE IS A NET EXCESS OF SHIPPER SUPPLIED GAS OR AT TRANSCO’S MONTHLY WACOG WHEN THERE IS A DEFICIENCY OF SHIPPER SUPPLIED GAS.


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Shipper Supplied Gas for the Current Quarter
  1. Report monthly (1) shipper supplied gas for the current quarter and gas consumed in pipeline operations, (2) the disposition of any excess, the accounting recognition given to such disposition and the specific account(s) charged or credited, and (3) the source of gas used to meet any deficiency, the accounting recognition given to the gas used to meet the deficiency, including the accounting basis of the gas and the specific account(s) charged or credited.
  2. On lines 7, 14, 22 and 30 report only the dekatherms of gas provided by shippers under tariff terms and conditions for gathering , production/ extraction/processing, transmission, distribution and storage service and the use of that gas for compressor fuel, other operational purposes and lost and unaccounted for. The dekatherms must be broken out by functional categories on Lines 2-6, 9-13, 16-21 and 24-29. The dekatherms must be reported in column (d) unless the company has discounted or negotiated rates which should be reported in columns (b) and (c).
  3. On lines 7, 14, 22 and 30 report only the dollar amounts of gas provided by shippers under tariff terms and conditions for gathering, production/ extraction/processing, transmission, distribution and storage service and the use of that gas for compressor fuel, other operational purposes and lost and unaccounted for. The dollar amounts must be broken out by functional categories on Lines 2-6, 9-13, 16-21 and 23-29. The dollar amounts must be reported in column (h) unless the company has discounted or negotiated rates which should be reported in columns (f) and (g). The accounting should disclose the account(s) debited and credited in columns (m) and (n).
  4. Indicate in a footnote the basis for valuing the gas reported in Columns (f), (g) and (h).
  5. Report in columns (j), (k) and (l) the amount of fuel waived, discounted or reduced as part of a negotiated rate agreement.
  6. On lines 32-37 report the dekatherms and dollar value of the excess or deficiency in shipper supplied gas broken out by functional category and whether recourse rate, discounted or negotiated rate.
  7. On lines 39 through 51 report the dekatherms, the dollar amount and the account(s) credited in Column (o) for the dispositions of gas listed in column (a).
  8. On lines 53 through 65 report the dekatherms, the dollar amount and the account(s) debited in Column (n) for the sources of gas reported in column (a).
  9. On lines 66 and 67, report forwardhaul and backhaul volume in Dths of throughput.
  10. Where appropriate, provide a full explanation of the allocation process used in reported numbers in a footnote.
Month 2
Amount Collected (Dollars) Volume (in Dth) Not Collected
Line No.
Item
(a)
Discounted rate Dth
(b)
Negotiated Rate Dth
(c)
Recourse Rate Dth
(d)
Total Dth
(e)
Discounted Rate, Amount
(f)
Negotiated Rate Amount
(g)
Recourse rate Amount
(h)
Total Amount
(i)
Waived Dth
(j)
Discounted Dth
(k)
Negotiated Dth
(l)
Total Dth
(m)
Account(s) Debited
(n)
Account(s) Credited
(o)
1
SHIPPER SUPPLIED GAS (LINES 13 AND 14 , PAGE 520)
2
Gathering
3
Production/Extraction/Processing
4
Transmission
24,923
31,156
4,028,329
4,084,408
98,032
122,548
15,845,030
16,065,610
5
Distribution
6
Storage
80,539
80,539
316,792
316,792
7
Total Shipper Supplied Gas
24,923
31,156
4,108,868
4,164,947
98,032
122,548
16,161,822
16,382,402
8
LESS GAS USED FOR COMPRESSOR STATION FUEL (LINE 28, PAGE 520)
9
Gathering
10
Production/Extraction/Processing
11
Transmission
15,592
19,491
2,520,158
2,555,241
61,330
76,667
9,912,788
10,050,785
12
Distribution
13
Storage
166,709
166,709
655,733
655,733
14
Total gas used in compressors
15,592
19,491
2,686,867
2,721,950
61,330
76,667
10,568,521
10,706,518
15
LESS GAS USED FOR OTHER DELIVERIES AND GAS USED FOR OTHER OPERATIONS (LINE 29, PAGE 520) (Footnote)
16
Gathering
17
Production/Extraction/Processing
18
Transmission
615
769
99,365
100,749
1,885
2,356
304,643
308,884
19
Distribution
20
Storage
21
Other Deliveries (specify) (footnote details)
22
Total Gas Used For Other Deliveries And Gas Used For Other Operations
615
769
99,365
100,749
1,885
2,356
304,643
308,884
23
LESS GAS LOST AND UNACCOUNTED FOR (LINE 32, PAGE 520)
24
Gathering
25
Production/Extraction/Processing
26
Transmission
9,186
11,500
1,484,821
1,505,507
36,422
45,597
5,887,296
5,969,315
27
Distribution
28
Storage
29
Other Deliveries (specify) (footnote details)
30
Total Gas Lost And Unaccounted For
9,186
11,500
1,484,821
1,505,507
36,422
45,597
5,887,296
5,969,315
30.1
NET EXCESS OR (DEFICIENCY)
31
Other Losses
32
Gathering
33
Production/Extraction/Processing
34
Transmission
275
344
44,506
45,125
1,616
2,021
261,259
264,896
35
Distribution
36
Storage
86,170
86,170
338,941
338,941
37
Total Net Excess Or (Deficiency)
275
344
41,664
41,045
1,616
2,021
77,682
74,045
38
DISPOSITION OF EXCESS GAS:
39
Gas sold to others
40
Gas used to meet imbalances
41
Gas added to system gas
42
Gas returned to shippers
43.1
43.2
43.3
43.4
43.5
43.6
43.7
43.8
51
Total Disposition Of Excess Gas
52
GAS ACQUIRED TO MEET DEFICIENCY:
53
System gas
54
Purchased gas
55.1
Gas used to meet imbalances
275
344
41,664
41,045
1,616
2,021
77,682
74,045
65
Total Gas Acquired To Meet Deficiency
275
344
41,664
41,045
1,616
2,021
77,682
74,045


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
Shipper Supplied Gas for the Current Quarter
  1. Report monthly (1) shipper supplied gas for the current quarter and gas consumed in pipeline operations, (2) the disposition of any excess, the accounting recognition given to such disposition and the specific account(s) charged or credited, and (3) the source of gas used to meet any deficiency, the accounting recognition given to the gas used to meet the deficiency, including the accounting basis of the gas and the specific account(s) charged or credited.
  2. On lines 7, 14, 22 and 30 report only the dekatherms of gas provided by shippers under tariff terms and conditions for gathering , production/ extraction/processing, transmission, distribution and storage service and the use of that gas for compressor fuel, other operational purposes and lost and unaccounted for. The dekatherms must be broken out by functional categories on Lines 2-6, 9-13, 16-21 and 24-29. The dekatherms must be reported in column (d) unless the company has discounted or negotiated rates which should be reported in columns (b) and (c).
  3. On lines 7, 14, 22 and 30 report only the dollar amounts of gas provided by shippers under tariff terms and conditions for gathering, production/ extraction/processing, transmission, distribution and storage service and the use of that gas for compressor fuel, other operational purposes and lost and unaccounted for. The dollar amounts must be broken out by functional categories on Lines 2-6, 9-13, 16-21 and 23-29. The dollar amounts must be reported in column (h) unless the company has discounted or negotiated rates which should be reported in columns (f) and (g). The accounting should disclose the account(s) debited and credited in columns (m) and (n).
  4. Indicate in a footnote the basis for valuing the gas reported in Columns (f), (g) and (h).
  5. Report in columns (j), (k) and (l) the amount of fuel waived, discounted or reduced as part of a negotiated rate agreement.
  6. On lines 32-37 report the dekatherms and dollar value of the excess or deficiency in shipper supplied gas broken out by functional category and whether recourse rate, discounted or negotiated rate.
  7. On lines 39 through 51 report the dekatherms, the dollar amount and the account(s) credited in Column (o) for the dispositions of gas listed in column (a).
  8. On lines 53 through 65 report the dekatherms, the dollar amount and the account(s) debited in Column (n) for the sources of gas reported in column (a).
  9. On lines 66 and 67, report forwardhaul and backhaul volume in Dths of throughput.
  10. Where appropriate, provide a full explanation of the allocation process used in reported numbers in a footnote.
Month 3
Amount Collected (Dollars) Volume (in Dth) Not Collected
Line No.
Item
(a)
Discounted rate Dth
(b)
Negotiated Rate Dth
(c)
Recourse Rate Dth
(d)
Total Dth
(e)
Discounted Rate, Amount
(f)
Negotiated Rate Amount
(g)
Recourse rate Amount
(h)
Total Amount
(i)
Waived Dth
(j)
Discounted Dth
(k)
Negotiated Dth
(l)
Total Dth
(m)
Account(s) Debited
(n)
Account(s) Credited
(o)
1
SHIPPER SUPPLIED GAS (LINES 13 AND 14 , PAGE 520)
2
Gathering
3
Production/Extraction/Processing
4
Transmission
27,360
35,126
4,405,278
4,467,764
118,266
151,830
19,041,814
19,311,910
5
Distribution
6
Storage
117,345
117,345
507,224
507,224
7
Total Shipper Supplied Gas
27,360
35,126
4,522,623
4,585,109
118,266
151,830
19,549,038
19,819,134
8
LESS GAS USED FOR COMPRESSOR STATION FUEL (LINE 28, PAGE 520)
9
Gathering
10
Production/Extraction/Processing
11
Transmission
16,083
20,648
2,589,557
2,626,288
69,520
89,250
11,193,360
11,352,130
12
Distribution
13
Storage
192,630
192,630
832,643
832,643
14
Total gas used in compressors
16,083
20,648
2,782,187
2,818,918
69,520
89,250
12,026,003
12,184,773
15
LESS GAS USED FOR OTHER DELIVERIES AND GAS USED FOR OTHER OPERATIONS (LINE 29, PAGE 520) (Footnote)
16
Gathering
17
Production/Extraction/Processing
18
Transmission
148
190
23,790
24,128
544
698
87,550
88,792
19
Distribution
20
Storage
21
Other Deliveries (specify) (footnote details)
22
Total Gas Used For Other Deliveries And Gas Used For Other Operations
148
190
23,790
24,128
544
698
87,550
88,792
23
LESS GAS LOST AND UNACCOUNTED FOR (LINE 32, PAGE 520)
24
Gathering
25
Production/Extraction/Processing
26
Transmission
8,276
10,625
1,332,483
1,351,384
35,772
45,925
5,759,660
5,841,357
27
Distribution
28
Storage
29
Other Deliveries (specify) (footnote details)
30
Total Gas Lost And Unaccounted For
8,276
10,625
1,332,483
1,351,384
35,772
45,925
5,759,660
5,841,357
30.1
NET EXCESS OR (DEFICIENCY)
31
Other Losses
32
Gathering
33
Production/Extraction/Processing
34
Transmission
2,853
3,663
459,448
465,964
12,430
15,957
2,001,244
2,029,631
35
Distribution
36
Storage
75,285
75,285
325,419
325,419
37
Total Net Excess Or (Deficiency)
2,853
3,663
384,163
390,679
12,430
15,957
1,675,825
1,704,212
38
DISPOSITION OF EXCESS GAS:
39
Gas sold to others
40
Gas used to meet imbalances
2,853
3,663
384,163
390,679
12,430
15,957
1,675,825
1,704,212
41
Gas added to system gas
42
Gas returned to shippers
43.1
43.2
43.3
43.4
43.5
43.6
43.7
43.8
51
Total Disposition Of Excess Gas
2,853
3,663
384,163
390,679
12,430
15,957
1,675,825
1,704,212
52
GAS ACQUIRED TO MEET DEFICIENCY:
53
System gas
54
Purchased gas
65
Total Gas Acquired To Meet Deficiency


Name of Respondent:

Transcontinental Gas Pipe Line Company, LLC
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/12/2019
Year/Period of Report:

End of:
2018
/
Q4
System Maps
  1. Furnish five copies of a system map (one with each filed copy of this report) of the facilities operated by the respondent for the production, gathering, transportation, and sale of natural gas. New maps need not be furnished if no important change has occurred in the facilities operated by the respondent since the date of the maps furnished with a previous year's annual report. If, however, maps are not furnished for this reason, reference should be made in the space below to the year's annual report with which the maps were furnished.
  2. Indicate the following information on the maps: (a) Transmission lines. (b) Incremental facilities. (c) Location of gathering areas. (d) Location of zones and rate areas. (e) Location of storage fields. (f) Location of natural gas fields. (g) Location of compressor stations. (h) Normal direction of gas flow (indicated by arrows). (i) Size of pipe. (j) Location of products extraction plants, stabilization plants, purification plants, recycling areas, etc. (k) Principal communities receiving service through the respondent's pipeline.
  3. In addition, show on each map: graphic scale of the map; date of the facts the map purports to show; a legend giving all symbols and abbreviations used; designations of facilities leased to or from another company, giving name of such other company.
  4. Maps not larger than 24 inches square are desired. If necessary, however, submit larger maps to show essential information. Fold the maps to a size not larger then this report. Bind the maps to the report.

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