21310215317103184201042152310524611063107486108799109111012110141115121611218131911331441145151115116111161172181194205226237248259261271012810230331103324331043453510536638106397710716911091332103412313441335156361671368181919210201511212912233113251614261115275162822172932183037193110203316213536221142323024312425246278287929820309343211334121711327315451618717259222910237122423145616681771198219231024111123755172134235274695714685191021015712169217111022013103291443015104310.2175320.41105340.216610.151720.221073410846958109101010111211012131113151111417121519113192114202315212516222717122123121341224523561236724781248102591226101512611161271217281318128142029121129322305233172413192513210263312Other (Define) (footnote details)Other (Specify) (footnote details)-1480555-3724487-987703-1950399-316026-3158778-5485728-534966-1763864210062501006250Other (Define) (footnote details)Other (Specify) (footnote details)R0027031O23Other (Specify) (footnote details)1Other (Define) (footnote details)4564568Other Clearing (Specify) (footnote details):1012255162747PREFERRED STOCK565865671COMMON STOCK21TOTAL COMMON STOCK (ACCT 201)34TOTAL PREFERRED STOCK (ACCT 204)568FalseOriginal value: N101101NoneNone R002703 0-6 2018-12-31 R002703 0-13 2018-12-31 R002703 0-9 2018-12-31 R002703 0-3 2018-12-31 R002703 0-7 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-30 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 0-25 2018-01-01 2018-12-31 R002703 0-9 ferc:GasUtilityMember 2018-12-31 R002703 1-7 1-7 2017-12-31 R002703 0-30 2018-01-01 2018-12-31 R002703 0-6 2017-12-31 R002703 1-36 2018-01-01 2018-12-31 R002703 0-24 0-24 2017-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-75 2018-01-01 2018-12-31 R002703 0-27 2018-01-01 2018-12-31 R002703 0-20 2017-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 0-16 2017-12-31 R002703 0-22 2018-01-01 2018-12-31 R002703 0-23 0-23 2018-12-31 R002703 0-56 2017-01-01 2017-12-31 R002703 ScheduleTransmissionAndCompressionOfGasByOthersAbstract 2018-01-01 2018-12-31 R002703 0-28 2018-01-01 2018-12-31 R002703 0-2 0-2 2017-12-31 R002703 0-13 2018-01-01 2018-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-22 ferc:GasUtilityMember 2018-12-31 R002703 ScheduleGasStorageProjectsAbstract 2018-01-01 2018-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-17 2018-01-01 2018-12-31 R002703 0-9 0-9 2018-12-31 R002703 0-31 2018-01-01 2018-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 0-4 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-22 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-17 0-17 2018-01-01 2018-12-31 R002703 1-6 2018-01-01 2018-12-31 R002703 0-5 2018-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 0-5 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-20 2018-01-01 2018-12-31 R002703 0-34 2018-01-01 2018-12-31 R002703 0-5 2017-12-31 R002703 0-17 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-14 2018-12-31 R002703 0-21 2018-12-31 R002703 1-21 2018-01-01 2018-12-31 R002703 0-17 2018-12-31 R002703 0-7 2017-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-3 2018-12-31 R002703 0-25 2018-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 0-22 2018-01-01 2018-12-31 R002703 1-1 2018-01-01 2018-12-31 R002703 0-5 2018-12-01 2018-12-31 R002703 0-4 2017-12-31 R002703 0-11 2018-01-01 2018-12-31 R002703 0-10 2017-12-31 R002703 ferc:DistributionPlantMember ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 1-10 1-10 2017-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-21 2018-01-01 2018-12-31 R002703 1-6 1-6 2018-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 1-5 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-31 ferc:GasUtilityMember 2018-12-31 R002703 0-20 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-6 ferc:GasUtilityMember 2018-12-31 R002703 1-8 1-8 2018-01-01 2018-12-31 R002703 0-20 2018-01-01 2018-12-31 R002703 0-5 2018-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 0-25 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 0-39 0-39 2018-12-31 R002703 0-15 2018-01-01 2018-12-31 R002703 0-4 2018-12-31 R002703 0-10 ferc:GasUtilityMember 2018-12-31 R002703 0-20 2018-01-01 2018-12-31 R002703 0-36 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 1-4 1-4 2018-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-8 2017-12-31 R002703 0-6 0-6 2018-01-01 2018-12-31 R002703 0-14 0-14 2018-01-01 2018-12-31 R002703 1-9 1-9 2017-12-31 R002703 0-10 2018-12-31 R002703 0-25 0-25 2017-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-1 2018-12-31 R002703 0-24 ferc:GasUtilityMember 2018-12-31 R002703 0-5 0-5 2018-12-31 R002703 1-26 2018-01-01 2018-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-8 2018-01-01 2018-12-31 R002703 0-15 2018-01-01 2018-12-31 R002703 0-14 2018-12-31 R002703 0-7 2018-12-31 R002703 0-32 0-32 2018-12-31 R002703 0-4 2018-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-20 0-20 2017-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 0-14 2018-12-31 R002703 0-15 2018-01-01 2018-12-31 R002703 0-31 2018-01-01 2018-12-31 R002703 0-23 2018-12-31 R002703 0 2018-01-01 2018-12-31 R002703 1-23 2018-01-01 2018-12-31 R002703 0-20 2018-01-01 2018-12-31 R002703 0-34 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-29 ferc:GasUtilityMember 2018-12-31 R002703 1-13 1-13 2018-12-31 R002703 0-1 2018-12-31 R002703 0-14 2018-01-01 2018-12-31 R002703 0-31 2018-01-01 2018-12-31 R002703 0-24 2018-01-01 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-18 0-18 2018-12-31 R002703 1-5 1-5 2018-01-01 2018-12-31 R002703 1-22 2018-01-01 2018-12-31 R002703 1-3 2018-01-01 2018-12-31 R002703 ferc:ProductionPlantManufacturedGasMember ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-3 2018-11-01 2018-11-30 R002703 0-9 2018-01-01 2018-12-31 R002703 ferc:GasUtilityMember 2017-12-31 R002703 0-20 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 R002703 0-4 ferc:GasUtilityMember 2018-12-31 R002703 0-17 2018-12-31 R002703 0-15 2018-01-01 2018-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-12 2017-12-31 R002703 0-29 2018-01-01 2018-12-31 R002703 0-15 2018-01-01 2018-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-15 0-15 2017-12-31 R002703 0-24 2018-01-01 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-26 2018-12-31 R002703 0-2 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-2 2017-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 0-9 2017-12-31 R002703 0-33 2018-01-01 2018-12-31 R002703 0-30 2017-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 1-2 1-2 2018-01-01 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-6 2017-12-31 R002703 0-12 2018-12-31 R002703 0-9 2018-12-31 R002703 1-1 1-1 2018-12-31 R002703 0-14 2018-12-31 R002703 0-8 0-8 2018-01-01 2018-12-31 R002703 0-15 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-39 0-39 2018-01-01 2018-12-31 R002703 0-67 2018-01-01 2018-12-31 R002703 0-5 2017-01-01 2017-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 0-20 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 1-5 2018-01-01 2018-12-31 R002703 0-8 ferc:GasUtilityMember 2018-12-31 R002703 1-1 1-1 2018-01-01 2018-12-31 R002703 0-14 2018-01-01 2018-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-18 2018-01-01 2018-12-31 R002703 0-23 2017-12-31 R002703 0-10 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-34 0-34 2018-01-01 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-17 2017-12-31 R002703 0-21 2018-01-01 2018-12-31 R002703 0-8 2017-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 ferc:GasUtilityMember 2017-01-01 2017-12-31 R002703 0-1 2018-12-31 R002703 1-24 2018-01-01 2018-12-31 R002703 0-3 2017-12-31 R002703 0-21 2018-01-01 2018-12-31 R002703 0-34 2018-01-01 2018-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-8 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 0-8 2018-12-31 R002703 0-3 2017-12-31 R002703 0-17 2018-01-01 2018-12-31 R002703 0-5 2018-10-01 2018-10-31 R002703 1-14 1-14 2017-12-31 R002703 0-12 0-12 2018-01-01 2018-12-31 R002703 ScheduleCompressorStationsAbstract 2018-01-01 2018-12-31 R002703 0-3 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-17 ferc:GasUtilityMember 2018-12-31 R002703 0-4 0-4 2017-12-31 R002703 0-31 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-1 2018-12-31 R002703 0-11 2018-01-01 2018-12-31 R002703 1-9 1-9 2018-01-01 2018-12-31 R002703 0-22 0-22 2018-01-01 2018-12-31 R002703 0-10 2018-12-31 R002703 0-19 0-19 2017-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 1-29 2018-01-01 2018-12-31 R002703 0-11 0-11 2018-12-31 R002703 0-27 0-27 2018-12-31 R002703 0-2 2018-12-31 R002703 0-5 2018-12-31 R002703 ScheduleGasUsedInUtilityOperationsAbstract 2018-01-01 2018-12-31 R002703 0-18 2017-12-31 R002703 1-14 1-14 2018-12-31 R002703 0-23 2018-12-31 R002703 0-34 2018-12-31 R002703 0-4 2017-12-31 R002703 0-15 2017-12-31 R002703 0-3 2017-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-25 2018-01-01 2018-12-31 R002703 ScheduleRevenuesFromTransportationOfGasOfOthersThroughTransmissionFacilitiesAbstract 2018-01-01 2018-12-31 R002703 0-32 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-12 0-12 2018-12-31 R002703 0-23 2017-12-31 R002703 0-6 2018-12-31 R002703 ferc:GasPlantInServiceMember ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 2016-12-31 R002703 0-11 0-11 2017-12-31 R002703 0-21 2017-12-31 R002703 0-14 2017-12-31 R002703 0-24 2017-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-8 2018-01-01 2018-12-31 R002703 0-9 0-9 2018-01-01 2018-12-31 R002703 1-6 1-6 2017-12-31 R002703 0-34 0-34 2017-12-31 R002703 0-13 2018-01-01 2018-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 0-14 2017-12-31 R002703 0-29 2017-12-31 R002703 0-25 2018-01-01 2018-12-31 R002703 1-27 2018-01-01 2018-12-31 R002703 0-30 2018-12-31 R002703 0-13 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 R002703 0-26 2017-12-31 R002703 1-16 1-16 2018-12-31 R002703 1-32 2018-01-01 2018-12-31 R002703 0-2 2017-12-31 R002703 0-11 2018-12-31 R002703 0-14 2018-01-01 2018-12-31 R002703 ScheduleRevenuesFromStoringGasOfOthersAbstract 2018-01-01 2018-12-31 R002703 1-7 1-7 2018-12-31 R002703 0-2 0-2 2018-12-31 R002703 0-35 0-35 2018-12-31 R002703 0-27 2018-01-01 2018-12-31 R002703 0-6 0-6 2018-12-31 R002703 0-14 0-14 2018-12-31 R002703 0-21 2018-01-01 2018-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 0-4 2017-12-31 R002703 0-36 2018-01-01 2018-12-31 R002703 0-3 2018-12-01 2018-12-31 R002703 0-30 2018-01-01 2018-12-31 R002703 0-2 2018-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 0-22 2018-12-31 R002703 0-14 2018-01-01 2018-12-31 R002703 0-18 2018-12-31 R002703 0-3 2018-12-31 R002703 0-67 2017-01-01 2017-12-31 R002703 1-1 1-1 2017-12-31 R002703 0-65 2017-01-01 2017-12-31 R002703 ferc:ElectricUtilityMember 2017-01-01 2017-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 0-6 2017-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-9 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-17 0-17 2017-12-31 R002703 0-19 2018-01-01 2018-12-31 R002703 ferc:NonUtilityMember 2017-12-31 R002703 1-11 2018-01-01 2018-12-31 R002703 0-7 2018-12-31 R002703 0-6 2018-12-31 R002703 0-19 2017-12-31 R002703 0-1 2018-12-31 R002703 0-33 2018-01-01 2018-12-31 R002703 0-3 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 1-2 1-2 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-3 2018-12-31 R002703 0-4 2018-12-31 R002703 0-18 2018-01-01 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 ScheduleShipperSuppliedGasForTheCurrentQuarterAbstract 2018-01-01 2018-12-31 R002703 0-30 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-16 2018-12-31 R002703 0-10 0-10 2018-01-01 2018-12-31 R002703 2018-01-01 2018-12-31 R002703 0-11 2017-12-31 R002703 0-12 2017-12-31 R002703 ferc:GasUtilityMember 2018-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 1-10 2018-01-01 2018-12-31 R002703 0-32 2018-01-01 2018-12-31 R002703 0-29 2018-01-01 2018-12-31 R002703 0-8 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-30 ferc:GasUtilityMember 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 1-15 1-15 2017-12-31 R002703 0-15 2018-01-01 2018-12-31 R002703 0-13 2017-12-31 R002703 0-25 2017-12-31 R002703 0-1 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-28 2017-12-31 R002703 0-11 2018-01-01 2018-12-31 R002703 0-13 2018-01-01 2018-12-31 R002703 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 R002703 0-15 2018-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 0-35 2018-01-01 2018-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-14 2018-01-01 2018-12-31 R002703 0-25 2018-01-01 2018-12-31 R002703 1-33 2018-01-01 2018-12-31 R002703 0-10 0-10 2018-12-31 R002703 0-5 2018-12-31 R002703 0-15 2018-12-31 R002703 0-8 2018-12-31 R002703 0-1 2018-12-31 R002703 0-29 2018-01-01 2018-12-31 R002703 ferc:PayrollBilledByAffiliatedCompaniesMember 2018-01-01 2018-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-35 0-35 2017-12-31 R002703 1-3 1-3 2018-01-01 2018-12-31 R002703 0-31 0-31 2018-01-01 2018-12-31 R002703 ferc:OperatingUtilityMember 2018-01-01 2018-12-31 R002703 0-3 2018-10-01 2018-10-31 R002703 0-6 2018-01-01 2018-12-31 R002703 0-24 2018-01-01 2018-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-22 2018-12-31 R002703 0-11 2018-01-01 2018-12-31 R002703 0-5 2018-11-01 2018-11-30 R002703 0-6 2018-01-01 2018-12-31 R002703 ferc:GeneralPlantMember ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 1-5 1-5 2017-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-9 0-9 2017-12-31 R002703 0-8 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-15 2018-01-01 2018-12-31 R002703 0-14 2017-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 1-7 2018-01-01 2018-12-31 R002703 0-6 2018-12-31 R002703 1-4 1-4 2017-12-31 R002703 0-5 2018-12-31 R002703 0-29 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-8 2018-01-01 2018-12-31 R002703 0-28 2018-01-01 2018-12-31 R002703 0-16 ferc:GasPlantInServiceMember ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-4 2018-11-01 2018-11-30 R002703 0-24 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-8 2018-01-01 2018-12-31 R002703 0-5 2017-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-35 2018-01-01 2018-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 1-2 2018-01-01 2018-12-31 R002703 0-47 2017-01-01 2017-12-31 R002703 0-28 0-28 2017-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-31 0-31 2017-12-31 R002703 0-35 0-35 2018-01-01 2018-12-31 R002703 0-27 2017-12-31 R002703 0-31 2018-01-01 2018-12-31 R002703 0-8 2018-01-01 2018-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 1-12 1-12 2018-01-01 2018-12-31 R002703 0-3 2018-12-31 R002703 0-18 0-18 2017-12-31 R002703 0-18 2018-01-01 2018-12-31 R002703 0-13 2018-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-8 2018-01-01 2018-12-31 R002703 0-5 0-5 2017-12-31 R002703 ferc:ElectricUtilityMember 2017-12-31 R002703 0-28 2018-12-31 R002703 0-30 0-30 2018-01-01 2018-12-31 R002703 0-17 2018-01-01 2018-12-31 R002703 0-8 2018-12-31 R002703 0-2 2018-12-31 R002703 0-16 2017-01-01 2017-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-23 2018-01-01 2018-12-31 R002703 0-20 2017-12-31 R002703 0-12 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-23 2018-01-01 2018-12-31 R002703 0-23 2018-01-01 2018-12-31 R002703 0-23 0-23 2017-12-31 R002703 0-12 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-19 0-19 2018-01-01 2018-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-4 0-4 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-30 2018-01-01 2018-12-31 R002703 1-13 1-13 2018-01-01 2018-12-31 R002703 0-9 2017-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-18 2018-12-31 R002703 0-12 2018-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-7 ferc:GasUtilityMember 2018-12-31 R002703 0-11 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-8 2018-01-01 2018-12-31 R002703 0-23 2018-01-01 2018-12-31 R002703 ferc:NonUtilityMember 2018-01-01 2018-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 1-31 2018-01-01 2018-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 2018-12-31 R002703 0-4 2018-12-31 R002703 0-26 0-26 2017-12-31 R002703 1-3 2018-01-01 2018-12-31 R002703 0-3 2018-12-31 R002703 0-33 0-33 2017-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-20 2018-01-01 2018-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-13 2017-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-3 2017-12-31 R002703 1-9 1-9 2018-12-31 R002703 0-58 2018-01-01 2018-12-31 R002703 0-9 2018-12-31 R002703 1-6 1-6 2018-01-01 2018-12-31 R002703 0-33 0-33 2018-01-01 2018-12-31 R002703 0-14 2018-01-01 2018-12-31 R002703 0-2 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 R002703 0-4 2018-12-31 R002703 0-15 2017-12-31 R002703 1-15 1-15 2018-01-01 2018-12-31 R002703 0-8 2018-01-01 2018-12-31 R002703 0-13 2018-12-31 R002703 0-38 0-38 2018-01-01 2018-12-31 R002703 0-28 2018-01-01 2018-12-31 R002703 1-14 1-14 2018-01-01 2018-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 0-26 2018-01-01 2018-12-31 R002703 0-24 2018-01-01 2018-12-31 R002703 0-28 0-28 2018-01-01 2018-12-31 R002703 1-4 2018-01-01 2018-12-31 R002703 0-18 2017-12-31 R002703 1-13 1-13 2017-12-31 R002703 ferc:OtherUtilityMember 2018-01-01 2018-12-31 R002703 0-25 0-25 2018-01-01 2018-12-31 R002703 0-32 0-32 2017-12-31 R002703 0-17 2018-01-01 2018-12-31 R002703 0-12 2018-12-31 R002703 0-8 2018-01-01 2018-12-31 R002703 0-25 2018-01-01 2018-12-31 R002703 0-24 2018-01-01 2018-12-31 R002703 0-18 2018-01-01 2018-12-31 R002703 0-21 2017-12-31 R002703 0-16 0-16 2017-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-19 2018-01-01 2018-12-31 R002703 0-17 2018-01-01 2018-12-31 R002703 0-25 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-21 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-29 2018-12-31 R002703 0-5 ferc:GasUtilityMember 2018-12-31 R002703 0-6 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 0-19 2018-01-01 2018-12-31 R002703 0-18 2018-01-01 2018-12-31 R002703 0-13 0-13 2018-12-31 R002703 0-1 2017-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-1 2017-12-31 R002703 1-9 2018-01-01 2018-12-31 R002703 1-2 2018-01-01 2018-12-31 R002703 0-25 0-25 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-4 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 R002703 0-3 ferc:GasUtilityMember 2018-12-31 R002703 0-23 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-33 0-33 2018-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-5 2018-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 0-16 2018-12-31 R002703 0-11 2018-01-01 2018-12-31 R002703 0-22 2018-12-31 R002703 0-15 2018-01-01 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 1-8 1-8 2018-12-31 R002703 0-10 0-10 2017-12-31 R002703 0-18 0-18 2018-01-01 2018-12-31 R002703 1-16 1-16 2018-01-01 2018-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 0-7 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-47 2018-01-01 2018-12-31 R002703 0-16 0-16 2018-01-01 2018-12-31 R002703 0-18 2017-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-3 2018-12-31 R002703 0-20 2018-12-31 R002703 0-26 2018-01-01 2018-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-14 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 ferc:CommonUtilityMember 2018-12-31 R002703 0-9 2018-12-31 R002703 1-13 2018-01-01 2018-12-31 R002703 0-23 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-13 2018-01-01 2018-12-31 R002703 0-15 0 2018-01-01 2018-12-31 R002703 2017-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-23 0-23 2018-01-01 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-23 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-34 0-34 2018-12-31 R002703 0-32 2018-12-31 R002703 0-18 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-15 2017-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 0-12 2017-12-31 R002703 0-7 2017-12-31 R002703 0-4 2018-12-31 R002703 0-21 2018-01-01 2018-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-7 2018-12-31 R002703 0-10 2017-12-31 R002703 0-16 0-16 2018-12-31 R002703 0-3 0-3 2018-12-31 R002703 0-27 0-27 2018-01-01 2018-12-31 R002703 1-5 1-5 2018-12-31 R002703 0-14 2017-12-31 R002703 0-17 0-17 2018-12-31 R002703 0-20 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-2 0-2 2018-01-01 2018-12-31 R002703 0-13 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-23 2018-01-01 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-2 2018-12-31 R002703 0-9 2018-12-31 R002703 0-9 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 ScheduleCapitalStockExpenseAbstract 2018-01-01 2018-12-31 R002703 0-13 2018-01-01 2018-12-31 R002703 ferc:DirectPayrollDistributionMember 2018-01-01 2018-12-31 R002703 0-16 2017-12-31 R002703 1-7 2018-01-01 2018-12-31 R002703 0-36 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-1 2018-12-31 R002703 0-17 2018-01-01 2018-12-31 R002703 0-5 2017-12-31 R002703 0-3 2018-12-31 R002703 ferc:GasPlantInServiceMember ferc:GasUtilityMember 2018-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 0-29 2018-01-01 2018-12-31 R002703 0-12 2017-12-31 R002703 0-14 2017-12-31 R002703 0-32 2017-12-31 R002703 0-3 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 1-10 1-10 2018-01-01 2018-12-31 R002703 2017-01-01 2017-12-31 R002703 0-11 ferc:GasUtilityMember 2018-12-31 R002703 0-4 2018-10-01 2018-10-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-9 2018-12-31 R002703 0-1 2017-12-31 R002703 ScheduleTransmissionLinesAbstract 2018-01-01 2018-12-31 R002703 0-7 2017-12-31 R002703 0-9 2017-12-31 R002703 0-32 0-32 2018-01-01 2018-12-31 R002703 0-3 2018-12-31 R002703 0-14 2018-12-31 R002703 0-34 2018-01-01 2018-12-31 R002703 ScheduleNonTraditionalRateTreatmentAffordedNewProjectsAbstract 2018-01-01 2018-12-31 R002703 0-25 2018-01-01 2018-12-31 R002703 0-17 2017-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-26 2018-01-01 2018-12-31 R002703 0-23 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-9 2017-12-31 R002703 0-7 2018-12-31 R002703 0-24 2018-01-01 2018-12-31 R002703 0-12 0-12 2017-12-31 R002703 0-20 2018-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-13 2018-01-01 2018-12-31 R002703 0-15 2018-01-01 2018-12-31 R002703 0-3 2017-12-31 R002703 0-11 2017-12-31 R002703 ScheduleGasPropertyAndCapacityLeasedToOthersAbstract 2018-01-01 2018-12-31 R002703 0-27 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-27 2018-01-01 2018-12-31 R002703 0-5 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-32 2018-01-01 2018-12-31 R002703 0-19 2018-01-01 2018-12-31 R002703 0-56 2018-01-01 2018-12-31 R002703 0-3 0-3 2018-01-01 2018-12-31 R002703 0-24 2018-01-01 2018-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-27 2018-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 0-1 2017-12-31 R002703 0-4 2018-12-01 2018-12-31 R002703 0-27 2018-01-01 2018-12-31 R002703 ferc:CommonPlantGasMember ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-15 2018-01-01 2018-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 ferc:ElectricUtilityMember 2018-12-31 R002703 0-31 0-31 2018-12-31 R002703 0-30 2018-01-01 2018-12-31 R002703 0-13 2018-12-31 R002703 0-14 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-21 2018-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 0-11 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 R002703 0-12 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 R002703 0-8 2018-01-01 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-3 0-3 2017-12-31 R002703 0-14 2018-01-01 2018-12-31 R002703 0-8 ferc:GasPlantInServiceMember ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-16 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-3 2018-12-31 R002703 0-17 2018-12-31 R002703 0-29 0 2018-01-01 2018-12-31 R002703 0-18 2018-12-31 R002703 0-11 2018-01-01 2018-12-31 R002703 0-6 2017-01-01 2017-12-31 R002703 0-12 2018-01-01 2018-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-17 2018-01-01 2018-12-31 R002703 0-14 2018-12-31 R002703 0-37 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 ferc:AllocationOfPayrollChargedForClearingAccountsMember 2018-01-01 2018-12-31 R002703 0-5 2017-12-31 R002703 0-23 ferc:GasUtilityMember 2018-12-31 R002703 0-3 2017-12-31 R002703 0-5 2018-01-01 2018-12-31 R002703 2018-11-01 2018-11-30 R002703 0-1 2018-01-01 2018-12-31 R002703 0-22 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 R002703 0-11 0-11 2018-01-01 2018-12-31 R002703 0-13 2018-01-01 2018-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-8 2018-01-01 2018-12-31 R002703 1-8 2018-01-01 2018-12-31 R002703 0-11 2017-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-4 0-4 2018-01-01 2018-12-31 R002703 0-21 2017-12-31 R002703 0-23 2018-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-17 2018-01-01 2018-12-31 R002703 0-21 2018-12-31 R002703 0-22 2018-01-01 2018-12-31 R002703 0-11 2018-01-01 2018-12-31 R002703 0-13 2017-12-31 R002703 0-6 2018-12-31 R002703 0-16 ferc:GasUtilityMember 2018-12-31 R002703 1-34 2018-01-01 2018-12-31 R002703 0-65 2018-01-01 2018-12-31 R002703 0-11 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-14 2018-01-01 2018-12-31 R002703 0-10 2018-01-01 2018-12-31 R002703 0-12 2018-12-31 R002703 0-26 0-26 2018-12-31 R002703 0-36 0-36 2018-01-01 2018-12-31 R002703 0-15 0-15 2018-12-31 R002703 0-27 2018-01-01 2018-12-31 R002703 1-4 1-4 2018-01-01 2018-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-21 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 2018-10-01 2018-10-31 R002703 0-21 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 R002703 0-29 2018-01-01 2018-12-31 R002703 0-10 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-22 2017-12-31 R002703 ScheduleGasPlantHeldForFutureUseAbstract 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-21 2018-01-01 2018-12-31 R002703 0-15 2018-12-31 R002703 0-27 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-27 2017-12-31 R002703 0-23 2017-12-31 R002703 0-15 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 R002703 0-39 0-39 2017-12-31 R002703 0-10 2018-12-31 R002703 0-17 2018-12-31 R002703 1-3 1-3 2018-12-31 R002703 0-6 2018-01-01 2018-12-31 R002703 1-4 2018-01-01 2018-12-31 R002703 ferc:NonUtilityMember 2018-12-31 R002703 ScheduleDiscountedRateServicesAndNegotiatedRateServicesAbstract 2018-01-01 2018-12-31 R002703 0-20 0-20 2018-01-01 2018-12-31 R002703 0-15 0-15 2018-01-01 2018-12-31 R002703 ferc:OperatingUtilityMember 2018-12-31 R002703 0-24 2017-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-14 0-14 2017-12-31 R002703 1-16 1-16 2017-12-31 R002703 0-23 2018-01-01 2018-12-31 R002703 0-19 0-19 2018-12-31 R002703 0-20 0-20 2018-12-31 R002703 0-34 2018-01-01 2018-12-31 R002703 0-28 0-28 2018-12-31 R002703 0-12 2018-12-31 R002703 1-28 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-8 2018-01-01 2018-12-31 R002703 0-5 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 R002703 1-9 2018-01-01 2018-12-31 R002703 0-37 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-16 2017-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-19 2018-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-5 0-5 2018-01-01 2018-12-31 R002703 0-4 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-16 2018-01-01 2018-12-31 R002703 0-6 2018-12-31 R002703 1-3 1-3 2017-12-31 R002703 1-10 1-10 2018-12-31 R002703 ScheduleRevenuesFromTransporationOfGasOfOthersThroughGatheringFacilitiesAbstract 2018-01-01 2018-12-31 R002703 0-36 ferc:GasUtilityMember 2018-12-31 R002703 0-10 2017-12-31 R002703 0-11 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-1 2018-12-31 R002703 0-20 2018-01-01 2018-12-31 R002703 0-7 2018-12-31 R002703 0-75 ferc:PayrollBilledByAffiliatedCompaniesMember 2018-01-01 2018-12-31 R002703 1-8 1-8 2017-12-31 R002703 0-27 0-27 2017-12-31 R002703 0-13 2018-01-01 2018-12-31 R002703 1-15 1-15 2018-12-31 R002703 ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-32 2018-01-01 2018-12-31 R002703 0-6 0-6 2017-12-31 R002703 0-22 2017-12-31 R002703 0-3 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-25 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-17 2018-01-01 2018-12-31 R002703 0-12 2017-12-31 R002703 0-13 2018-12-31 R002703 0-4 2018-12-31 R002703 ferc:GasPlantInServiceMember ferc:GasUtilityMember 2017-12-31 R002703 0-13 0-13 2017-12-31 R002703 0-19 2018-01-01 2018-12-31 R002703 0-36 0-36 2017-12-31 R002703 0-12 2018-12-31 R002703 0-11 2018-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 ScheduleDiscountOnCapitalStockAbstract 2018-01-01 2018-12-31 R002703 0-17 2017-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-25 2017-12-31 R002703 0-6 2017-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-7 2017-12-31 R002703 0-19 2017-12-31 R002703 ScheduleOtherGasSupplyExpensesAbstract 2018-01-01 2018-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 ScheduleTransmissionSystemPeakDeliveriesAbstract 2018-01-01 2018-12-31 R002703 0-24 0-24 2018-01-01 2018-12-31 R002703 0-18 2018-01-01 2018-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-20 2017-12-31 R002703 0-22 2018-01-01 2018-12-31 R002703 1-7 1-7 2018-01-01 2018-12-31 R002703 0-9 2018-01-01 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 1-2 1-2 2017-12-31 R002703 0-8 2018-12-31 R002703 0-75 ferc:DirectPayrollDistributionMember 2018-01-01 2018-12-31 R002703 0-11 2018-01-01 2018-12-31 R002703 0-26 0-26 2018-01-01 2018-12-31 R002703 0-7 2018-01-01 2018-12-31 R002703 0-9 2017-12-31 R002703 2018-12-01 2018-12-31 R002703 0-11 2018-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-1 0-1 2018-01-01 2018-12-31 R002703 0-15 2018-01-01 2018-12-31 R002703 0-2 2018-12-31 R002703 0-11 2018-01-01 2018-12-31 R002703 0-4 2018-01-01 2018-12-31 R002703 0-24 0-24 2018-12-31 R002703 0-1 2018-01-01 2018-12-31 R002703 0-19 2018-12-31 R002703 0-3 2017-12-31 R002703 0-24 2018-12-31 R002703 0-36 0-36 2018-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-22 2018-01-01 2018-12-31 R002703 0-34 2017-12-31 R002703 0-27 2018-12-31 R002703 0-3 2018-01-01 2018-12-31 R002703 0-17 2018-01-01 2018-12-31 R002703 0-21 2018-01-01 2018-12-31 R002703 0-21 2017-12-31 R002703 ferc:IntangiblePlantMember ferc:GasUtilityMember 2018-01-01 2018-12-31 R002703 0-2 2018-01-01 2018-12-31 R002703 0-13 0-13 2018-01-01 2018-12-31 R002703 0-15 2018-12-31 R002703 0-11 2018-12-31 R002703 ferc:OperatingUtilityMember 2017-12-31 R002703 0-19 2018-01-01 2018-12-31 R002703 0-24 2018-12-31 R002703 0-16 ferc:GasUtilityMember 2018-01-01 2018-12-31 iso4217:USD ferc:dth shares iso4217:USD shares ferc:dth iso4217:USD share pure iso4217:USD
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)

Duke Energy Ohio, Inc.
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

Duke Energy Ohio, Inc.
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)

139 East Fourth Street, Cincinnati, OH 45202
05 Name of Contact Person

Anna Anderson
06 Title of Contact Person

Accounting Analyst II
07 Address of Contact Person (Street, City, State, Zip Code)

550 South Tryon Street, Charlotte, NC 28202
08 Telephone of Contact Person, Including Area Code

980-373-2179
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

Dwight L. Jacobs
12 Title

SVP, CAO, Tax and Controller
13 Signature

Dwight L. Jacobs
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:

Duke Energy Ohio, Inc.
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
N/A
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
23
ScheduleInvestmentsInSubsidiaryCompaniesAbstract
Investments In Subsidiary Companies
224
12-96
24
SchedulePrepaymentsAbstract
Prepayments
230a
12-96
25
ScheduleExtraordinaryPropertyLossesAbstract
Extraordinary Property Losses
230b
12-96
26
ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract
Unrecovered Plant And Regulatory Study Costs
230c
12-96
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
31
ScheduleCapitalStockSubscribedLiabilityForConversionPremiumOnAndInstallmentsReceivedOnAbstract
Capital Stock Subscribed, Capital Stock Liability for Conversion, Premium on Capital Stock, and Installments Recieved on Capital Stock
252
12-96
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
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
N/A
49
ScheduleRevenuesFromTransportationOfGasOfOthersThroughTransmissionFacilitiesAbstract
Revenues From Transportation Of Gas Of Others Through Transmission Facilities
304
12-96
N/A
50
ScheduleRevenuesFromStoringGasOfOthersAbstract
Revenues From Storing Gas Of Others
306
12-96
N/A
51
ScheduleOtherGasRevenuesAbstract
Other Gas Revenues
308
12-96
52
ScheduleDiscountedRateServicesAndNegotiatedRateServicesAbstract
Discounted Rate Services And Negotiated Rate Services
313
NEW 12-07
N/A
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
N/A
56
ScheduleTransmissionAndCompressionOfGasByOthersAbstract
Transmission And Compression Of Gas By Others
332
12-96
N/A
57
ScheduleOtherGasSupplyExpensesAbstract
Other Gas Supply Expenses
334
12-96
N/A
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
N/A
67
ScheduleGasStorageProjectsAbstract
Gas Storage Projects
512
12-96
N/A
67
ScheduleGasStorageProjectsByCapacitiesAbstract
Gas Storage Projects
513
12-96
68
ScheduleTransmissionLinesAbstract
Transmission Lines
514
12-96
N/A
69
ScheduleTransmissionSystemPeakDeliveriesAbstract
Transmission System Peak Deliveries
518
12-96
N/A
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
N/A
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:

Duke Energy Ohio, Inc.
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.

Dwight L. Jacobs SVP, CAO, Tax and Controller 550 South Tryon Street Charlotte, NC 28202

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.

State of Ohio Date of Incorporation: April 3, 1837
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.

Ohio - Gas and Electric
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:

Duke Energy Ohio, Inc.
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
Cinergy Corp.
M
DE
100


Name of Respondent:

Duke Energy Ohio, Inc.
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
Duke Energy Beckjord, LLC
I
Public Utility
100
2
Duke Energy Kentucky, Inc.
D
Public Utility
100
3
KO Transmission Company
D
Transportation of Energy
100
4
Miami Power Corporation
D
Transmission of Electric
100
5
Ohio Valley Electric Corporation
J
Owns Generating Facility
9
6
Tri-State Improvement Company
D
Real Estate
100


Name of Respondent:

Duke Energy Ohio, Inc.
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:
89,663,086
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
9
10
11
12
13
14
15
16
17
18
19
20


Name of Respondent:

Duke Energy Ohio, Inc.
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. None

 

2. See Notes to Financial Statements, Note 2, "Acquisitions and Dispositions"

 

3. See Notes to Financial Statements, Note 2, "Acquisitions and Dispositions" and Note 4, "Regulatory Matters"

 

4. None

 

5. None

 

6. See Notes to Financial Statements, Note 6, "Debt and Credit Facilities"

 

7. None

8. During the fourth quarter 2018, there were no large wage scale changes to report.

 

During the third quarter 2018, there were no large wage scale changes to report.

 

During the second quarter 2018, employees bargained for by IBEW Local 1347, UWUA,

IUU Local 600, USW Local 12049 and USW Local 5541 received pay changes (pay rate

change/general wage increase)that totaled $730,907 in annualized costs.

 

During the first quarter 2018, employees bargained for by IBEW Local 1347, USW Local

12049, USW Local 5541, and UWUA/IUU Local 600 received pay changes (promotion, demotion, pay rate change/merit, job reclassification and adjustments) that totaled $42,993.60 in annualized costs or a monthly amount of approximately $3,582.80.

 

During the first quarter 2018, nonunion employees received pay changes (promotion, demotion, pay rate change/merit, job reclassification and adjustments) that totaled $218,662.07 in annualized costs or a monthly amount of approximately $18,221.84.

 

9. See Notes to Financial Statements, Note 4, "Regulatory Matters" and

Note 5, "Commitments and Contingencies"

 

10. None

 

11. None

 

12. There are no changes in major security holders and voting powers of Duke Energy Ohio, Inc. that occurred during the fourth quarter of 2018.

The changes in officers and directors for Duke Energy Ohio, Inc. that occurred during the fourth quarter of 2018 are as follows:

 

Appointments effective 11/01/18

Julia S. Janson Executive Vice President, External Affairs and Chief Legal Officer

David B. Fountain Senior Vice President, Legal, Chief Ethics and

Compliance Officer and Corporate Secretary

Sandra S. Wyckoff Vice President, Ethics and Compliance

Jackie Joyner Vice President Operations - Customer Delivery

Emily G. Henson Vice President Operations - Customer Delivery

Rufus Stanley Jackson Vice President Operations - Customer Delivery

Alexander J. Weintraub Senior Vice President and Chief Commercial Officer -

Natural Gas

Karl W. Newlin Senior Vice President, Corporate Development and

Treasurer

Donald E. Broadhurst Vice President Operations - Customer Delivery

Swati V. Daji Senior Vice President, Customer Solutions

Joni Y. Davis Vice President, Chief Diversity and Inclusion Officer

L. Standford Sherrill, Jr. Vice President, Talent Acquisition and Workforce Development

Appointments effective 10/16/18

Mia S. Haynes Vice President, Customer Care

Appointments effective 10/01/18

William H. Fowler Regional Senior Vice President, Customer Delivery

Midwest

Larry E. Hatcher Senior Vice President, Customer Delivery Governance,

Programs and Support

Resignations effective 12/31/18

Caren B. Anders Vice President, Operations Support

Christopher B. Heck Chief Information Officer

John F. Smith III Senior Vice President, Distribution Grid Performance and Contractor Operations

 

Resignations effective 11/01/18

Swati V. Daji Senior Vice President, Chief Procurement Officer

Joni Y. Davis Vice President, Marketing and Customer Engagement

Stephen G. De May Treasurer and Senior Vice President, Tax

Julia S. Janson Executive Vice President, External Affairs, Chief Legal Officer and Corporate Secretary

Karl W. Newlin Senior Vice President, Corporate Development

L. Stanford Sherrill, Jr. Vice President, Workforce Development, Diversity &

Inclusion

Alexander J. Weintraub Senior Vice President, Customer Solutions

Sandra S. Wyckoff Vice President and Chief Ethics and Compliance Officer

Resignations effective 10/01/18

William H. Fowler Vice President, Design Engineering & Consolidated

Planning Midwest

 

Resignations effective 09/14/18

Lisa M. Marcuz Vice President, Talent Management

 

 

There are no changes in major security holders and voting powers of Duke Energy Ohio, Inc. that occurred during the third quarter of 2018.

The changes in officers and directors for Duke Energy Ohio, Inc. that occurred during the third quarter of 2018 are as follows:

 

Appointments effective 09/03/18

Dennis P. Gilbert, Jr. Vice President and Chief Information Security Officer

Appointments effective 08/01/18

Rodney E. Gaddy Senior Vice President, Administrative Services

 

Appointments effective 07/16/18

Clark S. Gillespy Senior Vice President, Economic Development

Brian R. Weisker Vice President, Natural Gas Operational Excellence

 

Resignations effective 08/31/18

David J. Maxon Senior Vice President, Distribution Construction and Maintenance

 

Resignations effective 08/01/18

Rodney E. Gaddy Vice President, Administrative Services

 

 

Resignations effective 07/16/18

Larry E. Hatcher Vice President, Natural Gas Operational Excellence

Brian R. Weisker Vice President, Coal Combustion Products Operations and Maintenance

 

There are no changes in major security holders and voting powers of Duke Energy Ohio, Inc. that occurred during the second quarter of 2018.

The changes in officers and directors for Duke Energy Ohio, Inc. that occurred during the second quarter of 2018 are as follows:

 

Appointments effective 06/01/18

Harry K. Sideris Senior Vice President and Chief Distribution Officer

James M. Mosley Vice President, Midwest Generation

Amy B. Spiller President

James P. Henning Senior Vice President, Customer Services

William E. Currens Jr. Senior Vice President, Financial Planning and Analysis

Deborah T. Patton HR Director, Employee Relations

L. Stanford Sherrill, Jr. Vice President, Workforce Development, Diversity & Inclusion

Donna T. Council Vice President, HR Strategic Business Solutions

Karl W. Newlin Senior Vice President, Corporate Development

Dwight L. Jacobs Senior Vice President, Chief Accounting Officer and

Controller

 

 

Resignations effective 06/30/18

Jeffrey A. Corbett Senior Vice President, Distribution Engineering and Technical Customer Relations

Charles R. Whitlock Senior Vice President, Strategic Growth Initiatives

 

Resignations effective 06/01/18

Donna T. Council Vice President, Human Resources Business Partners

William E. Currens Jr. Senior Vice President, Chief Accounting Officer and

Controller

John B. Hayes Vice President, Midwest Generation

James P. Henning President

Michael A. Lewis Senior Vice President and Chief Distribution Officer

Karl W. Newlin Senior Vice President and Chief Commercial Officer,

Natural Gas Business

L. Stanford Sherrill, Jr. Vice President, Workforce Development, Employee and Labor Relations

Catherine S. Stempien Senior Vice President, Corporate Development

 

Resignations effective 05/04/18

Michael R. Delowery Vice President, Project Management and Construction

Resignations effective 04/30/18

Gayle S. Lanier Senior Vice President, Customer Services

 

 

There are no changes in major security holders and voting powers of Duke Energy Ohio, Inc. that occurred during the first quarter of 2018.

The changes in officers and directors for Duke Energy Ohio, Inc. that occurred during the first quarter of 2018 are as follows:

Appointments effective 03/15/18

Larry E. Hatcher Vice President, Natural Gas Operational Excellence

Appointments effective 03/01/18

Janice L. Walker Assistant Secretary

Michael S. Hendershott Assistant Treasurer

 

 

Resignations effective 03/15/18

Larry E. Hatcher Vice President, Environmental

Resignations effective 03/01/18

Kris C. Duffy Assistant Treasurer

 

13. N/A



Name of Respondent:

Duke Energy Ohio, Inc.
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
6,518,811,827
6,108,716,341
3
ConstructionWorkInProgress
Construction Work in Progress (107)
200-201
280,022,162
233,200,402
4
UtilityPlantAndConstructionWorkInProgress
TOTAL Utility Plant (Total of lines 2 and 3)
200-201
6,798,833,989
6,341,916,743
5
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
(Less) Accum. Provision for Depr., Amort., Depl. (108, 111, 115)
1,876,961,779
1,862,016,143
6
UtilityPlantNet
Net Utility Plant (Total of line 4 less 5)
4,921,872,210
4,479,900,600
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)
4,921,872,210
4,479,900,600
11
OtherGasPlantAdjustments
Utility Plant Adjustments (116)
122
12
GasStoredBaseGas
Gas Stored-Base Gas (117.1)
220
13
SystemBalancingGas
System Balancing Gas (117.2)
220
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)
14,816,484
11,467,225
18
AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty
(Less) Accum. Provision for Depreciation and Amortization (122)
2,481,406
2,572,272
19
InvestmentInAssociatedCompanies
Investments in Associated Companies (123)
222-223
20
InvestmentInSubsidiaryCompanies
Investments in Subsidiary Companies (123.1)
224-225
842,068,713
737,496,797
22
NoncurrentPortionOfAllowances
Noncurrent Portion of Allowances
23
OtherInvestments
Other Investments (124)
222-223
2,208,833
3,291,912
24
SinkingFunds
Sinking Funds (125)
25
DepreciationFund
Depreciation Fund (126)
26
AmortizationFundFederal
Amortization Fund - Federal (127)
27
OtherSpecialFunds
Other Special Funds (128)
17,456,858
6,829,037
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)
874,069,482
756,512,699
31
CurrentAndAccruedAssetsAbstract
CURRENT AND ACCRUED ASSETS
32
Cash
Cash (131)
13,157,913
9,653,608
33
SpecialDeposits
Special Deposits (132-134)
34
WorkingFunds
Working Funds (135)
35
TemporaryCashInvestments
Temporary Cash Investments (136)
222-223
36
NotesReceivable
Notes Receivable (141)
37
CustomerAccountsReceivable
Customer Accounts Receivable (142)
67,962,737
59,279,411
38
OtherAccountsReceivable
Other Accounts Receivable (143)
37,927,029
19,180,623
39
AccumulatedProvisionForUncollectibleAccountsCredit
(Less) Accum. Provision for Uncollectible Accounts - Credit (144)
1,786,068
2,350,148
40
NotesReceivableFromAssociatedCompanies
Notes Receivable from Associated Companies (145)
70,059,786
67,146,250
41
AccountsReceivableFromAssociatedCompanies
Accounts Receivable from Associated Companies (146)
33,367,362
75,428,358
42
FuelStock
Fuel Stock (151)
2,484,055
2,963,650
43
FuelStockExpensesUndistributed
Fuel Stock Expenses Undistributed (152)
44
ResidualsAndExtractedProducts
Residuals (Elec) and Extracted Products (Gas) (153)
45
PlantMaterialsAndOperatingSupplies
Plant Materials and Operating Supplies (154)
61,867,318
59,472,301
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)
1,805,847
3,178,224
50
NoncurrentPortionOfAllowances
(Less) Noncurrent Portion of Allowances
51
StoresExpenseUndistributed
Stores Expense Undistributed (163)
2,865,826
2,969,330
52
GasStoredCurrent
Gas Stored Underground-Current (164.1)
220
17,999,931
23,485,191
53
LiquefiedNaturalGasStoredAndHeldForProcessing
Liquefied Natural Gas Stored and Held for Processing (164.2 thru 164.3)
220
54
Prepayments
Prepayments (165)
230
58,479
344,934
55
AdvancesForGas
Advances for Gas (166 thru 167)
56
InterestAndDividendsReceivable
Interest and Dividends Receivable (171)
57
RentsReceivable
Rents Receivable (172)
38,140
30,350
58
AccruedUtilityRevenues
Accrued Utility Revenues (173)
59
MiscellaneousCurrentAndAccruedAssets
Miscellaneous Current and Accrued Assets (174)
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)
307,808,355
320,782,082
65
DeferredDebitsAbstract
DEFERRED DEBITS
66
UnamortizedDebtExpense
Unamortized Debt Expense (181)
6,298,703
6,962,196
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
442,178,415
381,212,664
70
PreliminarySurveyAndInvestigationCharges
Preliminary Survey and Investigation Charges (Electric)(183)
71
PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges
Preliminary Survey and Investigation Charges (Gas)(183.1 and 183.2)
1,536
72
ClearingAccounts
Clearing Accounts (184)
16,500
6,384
73
TemporaryFacilities
Temporary Facilities (185)
74
MiscellaneousDeferredDebits
Miscellaneous Deferred Debits (186)
233
759,787,610
755,317,622
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)
2,189,908
2,635,412
78
AccumulatedDeferredIncomeTaxes
Accumulated Deferred Income Taxes (190)
234-235
191,675,593
172,423,101
79
UnrecoveredPurchasedGasCosts
Unrecovered Purchased Gas Costs (191)
7,466,703
542,604
80
DeferredDebits
TOTAL Deferred Debits (Total of lines 66 thru 79)
1,394,681,562
1,318,002,007
81
AssetsAndOtherDebits
TOTAL Assets and Other Debits (Total of lines 10-15,30,64,and 80)
7,498,431,609
6,875,197,388


Name of Respondent:

Duke Energy Ohio, Inc.
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
762,136,231
762,136,231
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
2,775,280,826
2,669,915,712
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
663,676,963
871,542,471
12
UnappropriatedUndistributedSubsidiaryEarnings
Unappropriated Undistributed Subsidiary Earnings (216.1)
118-119
581,684,069
613,729,189
13
ReacquiredCapitalStock
(Less) Reacquired Capital Stock (217)
250-251
14
AccumulatedOtherComprehensiveIncome
Accumulated Other Comprehensive Income (219)
117
15
ProprietaryCapital
TOTAL Proprietary Capital (Total of lines 2 thru 14)
3,455,424,163
3,174,238,661
16
LongTermDebtAbstract
LONG TERM DEBT
17
Bonds
Bonds (221)
256-257
1,100,000,000
1,100,000,000
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
550,000,000
550,000,000
21
UnamortizedPremiumOnLongTermDebt
Unamortized Premium on Long-Term Debt (225)
258-259
3,537,781
3,970,033
22
UnamortizedDiscountOnLongTermDebtDebit
(Less) Unamortized Discount on Long-Term Debt-Dr (226)
258-259
34,189,814
36,343,777
23
CurrentPortionOfLongTermDebt
(Less) Current Portion of Long-Term Debt
450,000,000
24
LongTermDebt
TOTAL Long-Term Debt (Total of lines 17 thru 23)
1,169,347,967
1,617,626,256
25
OtherNoncurrentLiabilitiesAbstract
OTHER NONCURRENT LIABILITIES
26
ObligationsUnderCapitalLeaseNoncurrent
Obligations Under Capital Leases-Noncurrent (227)
1,103,593
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)
57,500,020
38,611,305
30
AccumulatedMiscellaneousOperatingProvisions
Accumulated Miscellaneous Operating Provisions (228.4)
31
AccumulatedProvisionForRateRefunds
Accumulated Provision for Rate Refunds (229)
21,249,199
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)
30,118,622
28,521,424
35
OtherNoncurrentLiabilities
TOTAL Other Noncurrent Liabilities (Total of lines 26 thru 34)
108,867,841
68,236,322
36
CurrentAndAccruedLiabilitiesAbstract
CURRENT AND ACCRUED LIABILITIES
37
CurrentPortionOfLongTermDebt
Current Portion of Long-Term Debt
450,000,000
38
NotesPayable
Notes Payable (231)
39
AccountsPayable
Accounts Payable (232)
234,051,356
238,972,552
40
NotesPayableToAssociatedCompanies
Notes Payable to Associated Companies (233)
234,906,000
29,356,000
41
AccountsPayableToAssociatedCompanies
Accounts Payable to Associated Companies (234)
55,824,361
41,082,000
42
CustomerDeposits
Customer Deposits (235)
34,460,718
36,116,871
43
TaxesAccrued
Taxes Accrued (236)
262-263
195,223,094
172,196,174
44
InterestAccrued
Interest Accrued (237)
15,436,351
15,207,034
45
DividendsDeclared
Dividends Declared (238)
46
MaturedLongTermDebt
Matured Long-Term Debt (239)
47
MaturedInterest
Matured Interest (240)
48
TaxCollectionsPayable
Tax Collections Payable (241)
101,515
90,831
49
MiscellaneousCurrentAndAccruedLiabilities
Miscellaneous Current and Accrued Liabilities (242)
268
22,636,800
18,647,314
50
ObligationsUnderCapitalLeasesCurrent
Obligations Under Capital Leases-Current (243)
1,103,594
2,264,709
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)
1,243,743,789
553,933,485
56
DeferredCreditsAbstract
DEFERRED CREDITS
57
CustomerAdvancesForConstruction
Customer Advances for Construction (252)
4,293,466
4,043,852
58
AccumulatedDeferredInvestmentTaxCredits
Accumulated Deferred Investment Tax Credits (255)
1,926,898
2,330,914
59
DeferredGainsFromDispositionOfUtilityPlant
Deferred Gains from Disposition of Utility Plant (256)
60
OtherDeferredCredits
Other Deferred Credits (253)
269
94,137,042
99,113,181
61
OtherRegulatoryLiabilities
Other Regulatory Liabilities (254)
278
613,636,577
593,458,019
62
UnamortizedGainOnReacquiredDebt
Unamortized Gain on Reacquired Debt (257)
260
197,049
238,533
63
AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty
Accumulated Deferred Income Taxes - Accelerated Amortization (281)
64
AccumulatedDeferredIncomeTaxesOtherProperty
Accumulated Deferred Income Taxes - Other Property (282)
738,088,664
699,763,874
65
AccumulatedDeferredIncomeTaxesOther
Accumulated Deferred Income Taxes - Other (283)
68,768,153
62,214,291
66
DeferredCredits
TOTAL Deferred Credits (Total of lines 57 thru 65)
1,521,047,849
1,461,162,664
67
LiabilitiesAndOtherCredits
TOTAL Liabilities and Other Credits (Total of lines 15,24,35,55,and 66)
7,498,431,609
6,875,197,388


Name of Respondent:

Duke Energy Ohio, Inc.
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
1,456,109,967
1,485,839,468
1,051,823,760
1,069,937,445
404,286,207
415,902,023
3
OperatingExpensesAbstract
Operating Expenses
4
OperationExpense
Operation Expenses (401)
317-325
584,418,735
671,202,267
420,806,180
515,717,785
163,612,555
155,484,482
5
MaintenanceExpense
Maintenance Expenses (402)
317-325
65,754,684
80,531,457
57,556,647
71,418,781
8,198,037
9,112,676
6
DepreciationExpense
Depreciation Expense (403)
336-338
154,995,298
145,562,304
109,944,417
99,491,329
45,050,881
46,070,975
7
DepreciationExpenseForAssetRetirementCosts
Depreciation Expense for Asset Retirement Costs (403.1)
336-338
8
AmortizationAndDepletionOfUtilityPlant
Amort. & Depl. of Utility Plant (404-405)
336-338
17,898,441
13,075,352
12,204,428
9,233,928
5,694,013
3,841,424
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)
47,930,488
70,010,647
25,260,412
46,926,944
22,670,076
23,083,703
13
RegulatoryCredits
(Less) Regulatory Credits (407.4)
22,987,241
22,519,034
22,678,819
22,263,025
308,422
256,009
14
TaxesOtherThanIncomeTaxesUtilityOperatingIncome
Taxes Other Than Income Taxes (408.1)
262-263
277,155,402
266,016,905
223,040,387
212,475,848
54,115,015
53,541,057
15
IncomeTaxesUtilityOperatingIncome
Income Taxes-Federal (409.1)
262-263
39,496,737
21,115,214
31,028,993
38,881,716
8,467,744
17,766,502
16
IncomeTaxesUtilityOperatingIncomeOther
Income Taxes-Other (409.1)
262-263
682,170
280,301
544,898
531,413
137,272
811,714
17
ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome
Provision of Deferred Income Taxes (410.1)
234-235
103,573,601
275,876,183
68,292,771
189,872,070
35,280,830
86,004,113
18
ProvisionForDeferredIncomeTaxesCreditUtilityOperatingIncome
(Less) Provision for Deferred Income Taxes-Credit (411.1)
234-235
93,218,740
198,154,368
64,685,563
122,157,242
28,533,177
75,997,126
19
InvestmentTaxCreditAdjustments
Investment Tax Credit Adjustment-Net (411.4)
404,016
415,822
233,230
231,244
170,786
184,578
20
GainsFromDispositionOfPlant
(Less) Gains from Disposition of Utility Plant (411.6)
21
LossesFromDispositionOfUtilityPlant
Losses from Disposition of Utility Plant (411.7)
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)
25
UtilityOperatingExpenses
TOTAL Utility Operating Expenses (Total of lines 4 thru 24)
1,175,295,559
1,280,350,978
861,081,521
961,072,045
314,214,038
319,278,933
26
NetUtilityOperatingIncome
Net Utility Operating Income (Total of lines 2 less 25) (Carry forward to line 27)
280,814,408
205,488,490
190,742,239
108,865,400
90,072,169
96,623,090
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)
2,728,260
1,916,712
32
CostsAndExpensesOfMerchandisingJobbingAndContractWork
(Less) Costs and Expense of Merchandising, Job & Contract Work (416)
1,165,777
1,961,207
33
RevenuesFromNonutilityOperations
Revenues From Nonutility Operations (417)
8,872
639
34
ExpensesOfNonutilityOperations
(Less) Expenses of Nonutility Operations (417.1)
411,226
142,850
35
NonoperatingRentalIncome
Nonoperating Rental Income (418)
58,387
58,499
36
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings of Subsidiary Companies (418.1)
119
32,045,120
58,476,337
37
InterestAndDividendIncome
Interest and Dividend Income (419)
4,960,050
4,512,287
38
AllowanceForOtherFundsUsedDuringConstruction
Allowance for Other Funds Used During Construction (419.1)
8,332,898
8,038,039
39
MiscellaneousNonoperatingIncome
Miscellaneous Nonoperating Income (421)
61,427
447,195
40
GainOnDispositionOfProperty
Gain on Disposition of Property (421.1)
25,165
269,461
41
OtherIncome
TOTAL Other Income (Total of lines 31 thru 40)
17,563,838
70,602,446
42
OtherIncomeDeductionsAbstract
Other Income Deductions
43
LossOnDispositionOfProperty
Loss on Disposition of Property (421.2)
61,153
175,914
44
MiscellaneousAmortization
Miscellaneous Amortization (425)
45
Donations
Donations (426.1)
340
696,069
819,630
46
LifeInsurance
Life Insurance (426.2)
167,834
39,580
47
Penalties
Penalties (426.3)
42
507
48
ExpendituresForCertainCivicPoliticalAndRelatedActivities
Expenditures for Certain Civic, Political and Related Activities (426.4)
1,666,045
1,763,876
49
OtherDeductions
Other Deductions (426.5)
11,678,744
8,133,364
50
OtherIncomeDeductions
TOTAL Other Income Deductions (Total of lines 43 thru 49)
340
14,269,887
10,932,871
51
TaxesApplicableToOtherIncomeAndDeductionsAbstract
Taxes Applic. to Other Income and Deductions
52
TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions
Taxes Other Than Income Taxes (408.2)
262-263
374,810
392,583
53
IncomeTaxesFederal
Income Taxes-Federal (409.2)
262-263
612,316
821,912
54
IncomeTaxesOther
Income Taxes-Other (409.2)
262-263
17,842
13,724
55
ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions
Provision for Deferred Income Taxes (410.2)
234-235
1,189,934
2,032,847
56
ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions
(Less) Provision for Deferred Income Taxes-Credit (411.2)
234-235
69,612
4,072,328
57
InvestmentTaxCreditAdjustmentsNonutilityOperations
Investment Tax Credit Adjustments-Net (411.5)
58
InvestmentTaxCredits
(Less) Investment Tax Credits (420)
59
TaxesOnOtherIncomeAndDeductions
TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)
2,125,290
811,262
60
NetOtherIncomeAndDeductions
Net Other Income and Deductions (Total of lines 41, 50, 59)
33,959,015
60,480,837
61
InterestChargesAbstract
INTEREST CHARGES
62
InterestOnLongTermDebt
Interest on Long-Term Debt (427)
81,274,665
80,523,776
63
AmortizationOfDebtDiscountAndExpense
Amortization of Debt Disc. and Expense (428)
258-259
3,084,894
3,086,286
64
AmortizationOfLossOnReacquiredDebt
Amortization of Loss on Reacquired Debt (428.1)
445,504
445,504
65
AmortizationOfPremiumOnDebtCredit
(Less) Amortization of Premium on Debt-Credit (429)
258-259
473,735
473,735
66
AmortizationOfGainOnReacquiredDebtCredit
(Less) Amortization of Gain on Reacquired Debt-Credit (429.1)
67
InterestOnDebtToAssociatedCompanies
Interest on Debt to Associated Companies (430)
340
2,055,484
13,946
68
OtherInterestExpense
Other Interest Expense (431)
340
2,544,138
2,097,660
69
AllowanceForBorrowedFundsUsedDuringConstructionCredit
(Less) Allowance for Borrowed Funds Used During Construction-Credit (432)
17,895,945
11,744,407
70
NetInterestCharges
Net Interest Charges (Total of lines 62 thru 69)
71,035,005
73,949,030
71
IncomeBeforeExtraordinaryItems
Income Before Extraordinary Items (Total of lines 27, 60 and 70)
175,820,388
192,020,297
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)
175,820,388
192,020,297


Name of Respondent:

Duke Energy Ohio, Inc.
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
2
Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income
3
Preceding Quarter/Year to Date Changes in Fair Value
4
Total (lines 2 and 3)
192,020,297
192,020,297
5
Balance of Account 219 at End of Preceding Quarter/Year
6
Balance of Account 219 at Beginning of Current Year
7
Current Quarter/Year to Date Reclassifications from Account 219 to Net Income
8
Current Quarter/Year to Date Changes in Fair Value
9
Total (lines 7 and 8)
175,820,388
175,820,388
10
Balance of Account 219 at End of Current Quarter/Year


Name of Respondent:

Duke Energy Ohio, Inc.
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
871,542,471
1,255,086,431
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)
207,865,508
133,543,960
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)
12
DividendsDeclaredCommonStock
Dividends Declared-Common Stock Amount
13
TransfersFromUnappropriatedUndistributedSubsidiaryEarnings
Transfers from Account 216.1, Unappropriated Undistributed Subsidiary Earnings
(b)
250,000,000
14
UnappropriatedRetainedEarnings
Balance-End of Period (Total of lines 1, 4, 5, 6, 8, 10, 12, and 13)
(a)
663,676,963
871,542,471
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)
663,676,963
871,542,471
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)
613,729,189
805,252,852
23
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings for Year (Credit) (Account 418.1)
32,045,120
58,476,337
24
DividendsReceived
(Less) Dividends Received (Debit)
(c)
250,000,000
25
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
Other Changes (Explain)
25.1
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
Other Changes (Explain)
26
UnappropriatedUndistributedSubsidiaryEarnings
Balance-End of Year
581,684,069
613,729,189


Name of Respondent:

Duke Energy Ohio, Inc.
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: UnappropriatedRetainedEarnings

 

Equity Amounts Available for Dividend to Duke Energy Ohio’s Parent(s)

 

On December 20, 2005, the Federal Energy Regulatory Commission ("FERC") issued an order approving the merger of Cinergy Corp. (“Cinergy”), a holding company and the parent company of Duke Energy Ohio, Inc. (“Duke Ohio”), and Duke Energy Corporation (“Duke Energy”). The merger closed on April 3, 2006 and now Cinergy is wholly owned by Duke Energy and Duke Ohio remains a wholly owned subsidiary of Cinergy. Under generally accepted accounting principles (“GAAP”), mergers resulting in a change of control must be accounted for by using purchase accounting. Purchase accounting treats a business combination, such as the merger of Duke Energy and Cinergy, as an acquisition of one company by another. Consequently, the purchase price paid for the acquired company is allocated to the acquired assets and liabilities based on their fair values. Under purchase accounting, if the acquiring company’s purchase price exceeds the fair value of the acquired company’s identifiable net assets, the excess is recorded as goodwill on the acquiring company’s balance sheets. The goodwill, and any other corresponding adjustments to the values of assets and liabilities of the acquired entity on the acquiring company’s balance sheet, must be reviewed to determine whether it must be then assigned or “pushed-down” to the balance sheets of the acquired entity or any of the acquired entity’s subsidiaries to the extent those subsidiaries file periodic reports with the Securities and Exchange Commission.

 

Upon the merger, Duke Energy determined that it needed to apply push-down accounting to Duke Ohio. The application of push-down accounting by Duke Ohio resulted in a one-time adjustment to certain of its assets and liabilities and a resetting of Duke Ohio’s retained earnings to zero (immediately prior to the closing, Duke Ohio’s retained earnings account was approximately $671 million). This push-down accounting was recorded in Duke Ohio’s Uniform System of Accounts balances.

 

The effects of applying push-down accounting included the recording of approximately $2.9 billion of goodwill and other increases to net assets being pushed down from Duke Energy’s balance sheet to the books of Duke Ohio, with offsetting entries to Other Paid-In Capital (accounts 208-211). Since the merger, Duke Ohio has analyzed goodwill for impairment under GAAP, and has written down goodwill on Duke Ohio’s books. Moreover, the other increases to net assets added to Duke Ohio’s books in purchase accounting have been amortized over time or impaired in accordance with GAAP. These non-cash amortization and impairment charges, in turn, are written off against Duke Ohio’s GAAP earnings, thereby decreasing the level of GAAP retained earnings recorded on Duke Ohio’s books.

 

Duke Ohio has received declaratory orders from the FERC (see Cincinnati Gas and Electric Company, d/b/a Duke Energy Ohio, et al., 115 FERC ¶ 61,250 (2006) and 137 FERC ¶ 61,137 (2011) with certain conditions, that Duke Ohio will not violate Section 305(a) of the FPA if they pay dividends from their equity accounts that are reflective of the amount that they would have had in their retained earnings account had push-down accounting not been in effect. The conditions of the declaratory orders include a commitment from Duke Ohio that equity, adjusted to remove the amounts that remain from the push-down of purchase accounting (“adjusted equity”), will not fall below 30% of total capital. As of December 31, 2018, Duke Ohio’s adjusted equity balance represents approximately 54% of total capital (total capital is calculated as adjusted equity plus long-term debt and current maturities of long-term debt of Duke Energy Ohio and its consolidated subsidiaries).

 

Additionally, Duke Ohio has committed to separately track, in sub-accounts of Account 211-Miscellaneous Paid-in Capital, the amounts subject to these orders. The purpose of the sub-accounts is to ensure that post-merger dividends that have been paid from equity accounts have not exceeded “adjusted retained earnings.” Adjusted retained earnings is defined for these purposes as (a) the amount in Duke Ohio's retained earnings account immediately prior to the closing of the merger plus (b) cumulative “adjusted net income,” representing cumulative post-merger reported net income excluding the impact of impairments and amortization of push-down accounting net assets and goodwill impairments, less (c) cumulative post-merger dividends.

 

As of December 31, 2018, the amount in Duke Ohio’s equity accounts available to be paid in the form of

dividends to its parent, Cinergy, is as follows:

 

 

In Millions

 

Retained earnings just prior to the April 3, 2006 merger $ 671

 

Post merger adjusted net income, cumulative 2,510

 

Post merger contribution from parent related to divesture of

MidWest Commercial Generation 9

 

Post-merger dividends, cumulative (1,655)

 

Retained earnings as of December 31, 2018, adjusted to remove the effects of

push-down accounting (“adjusted retained earnings”) $ 1,535

 

 

 

 

The equity accounts in which the adjusting amounts are tracked are as follows:

In Millions

Retained earnings as of December 31, 2018 – Sum of Lines 11 and 12 on page

112 (Retained Earnings and Unappropriated Undistributed Subsidiary Earnings) $ (82)

 

Add: Stated capital account, reflecting pre-merger retained earnings less

dividends applied to the account - tracked in a sub account of Account 211

– a component of the amount on line 7 on page 112 0

 

Add: Net after-tax losses attributable to impairments and amortization of pushdown

accounting net assets, cumulative – tracked in a sub account of

Account 211 – a component of the amount on line 7 on page 112 1,617

 

Retained earnings as of December 31, 2018, adjusted to remove the effects of

push-down accounting (“adjusted retained earnings”) $ 1,535

(b) Concept: TransfersFromUnappropriatedUndistributedSubsidiaryEarnings

 

2011-2016 Cumulative dividends from DEK to DEO

(c) Concept: DividendsReceived

 

2011-2016 Cumulative dividends from DEK to DEO


Name of Respondent:

Duke Energy Ohio, Inc.
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)
175,820,388
192,020,297
3
NoncashChargesCreditsToIncomeAbstract
Noncash Charges (Credits) to Income:
4
DepreciationAndDepletion
Depreciation and Depletion
154,995,298
145,562,304
5
NoncashAdjustmentsToCashFlowsFromOperatingActivities
Amortization of (Specify) (footnote details)
5.1
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Amortization of (Specify) (footnote details)
(a)
20,955,104
(o)
16,133,407
6
DeferredIncomeTaxesNet
Deferred Income Taxes (Net)
11,475,181
75,682,334
7
InvestmentTaxCreditAdjustmentsNet
Investment Tax Credit Adjustments (Net)
404,016
415,822
8
NetIncreaseDecreaseInReceivablesOperatingActivities
Net (Increase) Decrease in Receivables
(b)
16,423,860
(p)
45,669,604
9
NetIncreaseDecreaseInInventoryOperatingActivities
Net (Increase) Decrease in Inventory
(c)
3,673,342
(q)
581,392
10
NetIncreaseDecreaseInAllowancesInventoryOperatingActivities
Net (Increase) Decrease in Allowances Inventory
1,372,377
949,657
11
NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
20,910,056
26,090,934
12
NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Net (Increase) Decrease in Other Regulatory Assets
(d)
21,681,250
(r)
6,326,040
13
NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities
Net Increase (Decrease) in Other Regulatory Liabilities
49,391,522
12,611,072
14
AllowanceForOtherFundsUsedDuringConstructionOperatingActivities
(Less) Allowance for Other Funds Used During Construction
8,332,898
8,038,039
15
UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities
(Less) Undistributed Earnings from Subsidiary Companies
32,045,120
58,476,337
16
OtherAdjustmentsToCashFlowsFromOperatingActivities
Other Adjustments to Cash Flows from Operating Activities
16.1
OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Other (footnote details):
(e)
13,062,863
(s)
48,303,576
18
NetCashProvidedByUsedInOperatingActivities
Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 16)
443,581,221
313,891,275
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)
608,107,761
(t)
506,547,265
23
GrossAdditionsToNuclearFuelInvestingActivities
Gross Additions to Nuclear Fuel
24
GrossAdditionsToCommonUtilityPlantInvestingActivities
Gross Additions to Common Utility Plant
(g)
11,756,426
(u)
13,060,154
25
GrossAdditionsToNonutilityPlantInvestingActivities
Gross Additions to Nonutility Plant
26
AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
(Less) Allowance for Other Funds Used During Construction
(h)
8,332,898
(v)
8,038,039
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)
(i)
611,531,289
(w)
511,569,380
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
(j)
35,000,000
(x)
97,113,000
34
ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies
Contributions and Advances from Associated and Subsidiary Companies
36
DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
38
PurchaseOfInvestmentSecurities
Purchase of Investment Securities (a)
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
47
OtherAdjustmentsToCashFlowsFromInvestmentActivities
Other Adjustments to Cash Flows from Investment Activities:
47.1
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Other (footnote details):
(k)
1,083,079
(y)
153,864
49
CashFlowsProvidedFromUsedInInvestmentActivities
Net Cash Provided by (Used in) Investing Activities (Total of lines 28 thru 47)
645,448,210
414,302,516
51
CashFlowsFromFinancingActivitiesAbstract
Cash Flows from Financing Activities:
52
ProceedsFromIssuanceAbstract
Proceeds from Issuance of:
53
ProceedsFromIssuanceOfLongTermDebtFinancingActivities
Proceeds from Issuance of Long-Term Debt (b)
100,000,000
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):
(l)
205,550,000
(z)
29,356,000
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)
205,550,000
129,356,000
61
PaymentsForRetirementAbstract
Payments for Retirement
62
PaymentsForRetirementOfLongTermDebtFinancingActivities
Payments for Retirement of Long-Term Debt (b)
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):
(m)
178,706
(aa)
907,884
66
NetDecreaseInShortTermDebt
Net Decrease in Short-Term Debt (c)
67
OtherAdjustmentsToCashFlowsFromFinancingActivities
Other Adjustments to Financing Cash Flows
67.1
OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription
Distribution to Parent
(ab)
25,000,000
68
DividendsOnPreferredStock
Dividends on Preferred Stock
69
DividendsOnCommonStock
Dividends on Common Stock
70
CashFlowsProvidedFromUsedInFinancingActivities
Net Cash Provided by (Used in) Financing Activities (Total of lines 59 thru 69)
205,371,294
103,448,116
73
NetIncreaseDecreaseInCashAndCashEquivalentsAbstract
Net Increase (Decrease) in Cash and Cash Equivalents
74
NetIncreaseDecreaseInCashAndCashEquivalents
(Total of line 18, 49 and 71)
3,504,305
3,036,875
76
CashAndCashEquivalents
Cash and Cash Equivalents at Beginning of Period
9,653,608
6,616,733
78
CashAndCashEquivalents
Cash and Cash Equivalents at End of Period
(n)
13,157,913
9,653,608


Name of Respondent:

Duke Energy Ohio, Inc.
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

 

Amortization of:

Plant items $ 17,898,441

Debt discount, premium, expense and loss on reacquired debt 3,056,663

$ 20,995,104

(b) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: 16423860
(c) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: 3673342
(d) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -21681250
(e) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

 

Other:

 

 

 

 

 

 

 

Special funds

 

 

$ (1,758,260)

Prepayments

 

 

2,035,555

Preliminary Survey and Investigation Charges

 

(1,536)

Clearing Accounts

 

 

(22,883)

Miscellaneous Deferred Debits

 

(25,245,310)

Unrecovered Purchased Gas Costs

 

5,793,726

Obligations Under Capital Leases - Noncurrent

 

(1,103,593)

Accumulated Provisions

 

(810,333)

Accumulated Provision for Rate Refund

 

21,249,199

Contribution to Pension Plan

 

(420,897)

Customer Advances for Construction

 

249,614

Other Deferred Credits

 

(22,005,739)

Net Utility Plant and Nonutility Property

 

13,939,603

Debt Expenses

 

 

(88,734)

Deferred Income Taxes

 

(4,873,275)

 

 

 

 

TOTAL OTHER

 

 

$ (13,062,863)

(f) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -608107761
(g) Concept: GrossAdditionsToCommonUtilityPlantInvestingActivities
Original value: -11756426
(h) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -8332898
(i) Concept: CashOutflowsForPlant
Original value: -611531289
(j) Concept: InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Original value: -35000000
(k) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

 

Other:

Other Investments $ 1,083,079

(l) Concept: OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities

 

Other:

Notes Payable to Associated Companies $ 205,550,000

(m) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: -178706
(n) Concept: CashAndCashEquivalents

YTD YTD

Dec 2018 Dec 2017

 

Supplemental Disclosures:

Cash paid for interest, net of amount capitalized $ 70,332,578 $ 73,056,535

Cash paid/(refunded) for income taxes $ 18,144,109 $ 10,449,046

 

 

Significant non-cash transactions:

Accrued capital expenditures $ 45M $ 49M

 

 

Cash and Cash Equivalents at End of period:

Cash (131) $ 13,157,913 $ 9,653,608

Working Fund (135) 0 0

Temporary Cash Investments (136) 0 0

$ 13,157,913 $ 9,653,608

(o) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities

 

Amortization of:

Plant items $ 13,075,352

Debt discount, premium, expense and loss on reacquired debt 3,058,055

$ 16,133,407

(p) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: -45669604
(q) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: -581392
(r) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: 6326040
(s) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

 

Other:

 

 

 

 

 

Special funds

 

$ (2,249,859)

Prepayments

 

(10,725,142)

Miscellaneous Current and Accrued Assets

 

2,300,000

Clearing Accounts

 

6,384

Miscellaneous Deferred Debits

 

3,765,044

Unrecovered Purchased Gas Costs

 

1,440,913

Obligations Under Capital Leases - Noncurrent

 

(3,352,697)

Accumulated Provisions

 

2,710,901

Contribution to Pension Plan

 

(2,221,973)

Customer Advances for Construction

 

7,968

Other Deferred Credits

 

(16,268,754)

Net Utility Plant and Nonutility Property

 

10,796,231

Investment in Subsidiary Companies (I/C Equitization-Other)

(13,601,147)

Investment in Subsidiary Companies (KO Equitization)

 

(19,717,872)

Debt Expenses

 

(6,994,040)

Deferred Income Taxes

 

5,800,467

TOTAL OTHER

 

 

 

 

$ (48,303,576)

(t) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -506547265
(u) Concept: GrossAdditionsToCommonUtilityPlantInvestingActivities
Original value: -13060154
(v) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -8038039
(w) Concept: CashOutflowsForPlant
Original value: -511569380
(x) Concept: InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Original value: 97113000
(y) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

 

Other:

Other Investments $ 153,864

(z) Concept: OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities

 

Other:

Notes Payable to Associated Companies $ 29,356,000

 

(aa) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: -907884
(ab) Concept: OtherAdjustmentsToCashFlowsFromFinancingActivities
Original value: -25000000

Name of Respondent:

Duke Energy Ohio, Inc.
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.

This Federal Energy Regulatory Commission (FERC) Form 1 has been prepared in conformity with the requirements of the FERC as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than Generally Accepted Accounting Principles in the United States of America (GAAP). The following areas represent the significant differences between the Uniform System of Accounts and GAAP:

 

  • GAAP requires that public business enterprises report certain information about operating segments in complete sets of financial statements of the enterprise and certain information about their products and services, which are not required for FERC reporting purposes.

 

 

 

  • GAAP requires that majority-owned subsidiaries be consolidated for financial reporting purposes. FERC requires that majority-owned subsidiaries be separately reported as Investment in Subsidiary Companies, unless an appropriate waiver has been granted by the FERC.

 

  • FERC requires that income or losses of an unusual nature and infrequent occurrence, which would significantly distort the current year’s income, be recorded as extraordinary income or deductions, respectively.

 

  • GAAP requires that removal and nuclear decommissioning costs for property that does not have an associated legal retirement obligation be presented as a regulatory liability on the Balance Sheet. These costs are presented as accumulated depreciation on the Balance Sheet for FERC reporting purposes.

 

  • GAAP requires the regulatory assets and liabilities resulting from the implementation of ASC 740-10 (formerly SFAS No. 109) be presented as a net amount on the balance sheet. For FERC reporting purposes, these assets and liabilities are presented separately and are included in the Other Regulatory Asset and Other Regulatory Liability line items.

 

  • GAAP requires that the current portion of regulatory assets and regulatory liabilities be reported as current assets and current liabilities, respectively, on the Balance Sheet. FERC requires that the current portion of regulatory assets and liabilities be reported as Regulatory Assets within Deferred Debits and Regulatory Liabilities within Deferred Credits, respectively.

 

  • GAAP requires that the current portion of long-term debt and preferred stock be reported as a current liability on the Balance Sheet. FERC requires that the current portion of long-term debt and preferred stock be reported as Long-term Debt and Proprietary Capital.

 

    • GAAP requires that any deferred costs associated with a specific debt issuance be presented as a reduction to debt on the Balance Sheet. FERC requires any Unamortized Debt Expense to be separately stated as a Deferred Debit on the Balance Sheet.

 

  • GAAP requires that certain account balances within financial statement line items which are not in the natural position for that line item (e.g. an account within Accounts Receivable with a credit balance) be reclassed to the appropriate side of the Balance Sheet.  FERC does not require certain accounts which are not in a natural position for their respective line item to be reclassed, as long as the line item in total is in its natural position.

 

    • GAAP requires that regulated assets that are abandoned or retired early, including the cost of the asset and its associated depreciation, be reclassified to a separate regulatory asset on the Balance Sheet. For FERC reporting purposes, those assets which have been abandoned but are still operating are maintained in their original balance sheet accounts.

 

    • GAAP requires that the current portion of Asset Retirement Obligations be reported as current liabilities on the Balance Sheet. For FERC reporting purposes, these liabilities are not reported separately and are reflected as Asset Retirement Obligations within the Other Noncurrent Liabilities section of the Balance Sheet.

 

 

 

 

    • With the adoption of Accounting Standards Update (ASU) No. 2017-17, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, on January 1, 2018, GAAP requires that the service cost related to pensions and post-retirement benefits other than pensions (PBOP) be reported with other compensation costs arising from services rendered by employees during the period be included in a subtotal of income from operations on the income statement,  while non-service cost components are to be presented in the income statement separately outside a subtotal of income from operations.  Only the service cost component may be eligible for capitalization if all other capitalization criteria are met.  For FERC reporting purposes, costs related to pensions and PBOP will be included in the Net Utility Operating Income of the income statement.   Duke has made a non-revocable election to capitalize only the service cost component of pension and PBOP costs, upon implementing ASU No. 2017-07.  This change is not expected to have a material impact on the financial statements. 

The Combined Notes To Consolidated Financial Statements below are as published in the fourth quarter ended December 31, 2018 Form 10-K (includes Duke Energy Carolinas, LLC, Duke Energy Progress, LLC, Duke Energy Florida, LLC, Duke Energy Ohio, Inc., Duke Energy Indiana, LLC, and Piedmont Natural Gas Company, Inc.) filed on February 28, 2019.  See “Index to the Combined Notes to Consolidated Financial Statements” for a listing of applicable notes for Duke Energy Ohio, Inc. Management has evaluated the impact of events occurring after December 31, 2018 up to February 28, 2019, the date that Duke Energy Ohio’s U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposes through April 12, 2019. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.

 

DEO Gas FERC Federal Tax Reform Disclosure

 

In December 2017, Duke Energy Ohio re-measured its deferred tax assets and liabilities to the new federal corporate income tax rate of 21%. The result of this re-measurement was a reduction in the net deferred tax liability of approximately $161 million. Based on our estimate of the amount of excess deferred income taxes (EDIT) that would be used to reduce future customer rates, we recorded an increase in regulatory liabilities of approximately $200 million. The additional $43 million in regulatory liabilities was required to reflect the future revenue reduction required to return $157 million of previously collected income taxes to customers. We also recorded a $43 million deferred tax asset related to the $157 million regulatory liability. The accounts that were debited and (credited) in the 2017 re-measurement of deferred income taxes are reflected below (in millions):

 

[image]

 

In December 2018, Duke Energy Ohio recorded adjustments to accumulated deferred income tax (ADIT) and excess deferred income taxes after filing the 2017 tax return. As of December 2018, the cumulative re-measurement is shown below (in millions):

 

[image]

 

The amount of excess deferred income taxes that is considered protected and unprotected as of December 31, 2018 and 2017 is reflected below (in millions):

 

[image]

 

Duke Energy Ohio has not received a regulatory order from the Public Utilities Commission of Ohio regarding how customer rates should be reduced for excess deferred income taxes. The reduction in the excess deferred income tax regulatory liability was offset against account 411.1, the account to which the original re-measurement of deferred income taxes was recorded in December 2017. The estimated amortization period based on regulatory orders, and the account that the amortization will be reported in, is reflected below.

 

[image]

 

* Duke Energy Ohio plans to seek regulatory direction. At this time we cannot predict the outcome of this matter.

In the table above, ARAM refers to the average rate assumption method.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Index to Combined Notes To Consolidated Financial Statements

The notes to the consolidated financial statements are a combined presentation. The following table indicates the registrants to which the notes apply.

 

Applicable Notes

Registrant

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

Duke Energy

 

Duke Energy Carolinas

 

 

 

Progress Energy

 

 

 

 

Duke Energy Progress

 

 

 

 

 

Duke Energy Florida

 

 

 

 

 

Duke Energy Ohio

 

 

 

 

 

Duke Energy Indiana

 

 

 

 

Piedmont

 

 

 

 

 

Tables within the notes may not sum across due to (i) Progress Energy's consolidation of Duke Energy Progress, Duke Energy Florida and other subsidiaries that are not registrants and (ii) subsidiaries that are not registrants but included in the consolidated Duke Energy balances.

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations and Basis of Consolidation

Duke Energy is an energy company headquartered in Charlotte, North Carolina, subject to regulation by the FERC and other regulatory agencies listed below. Duke Energy operates in the U.S. primarily through its direct and indirect subsidiaries. Certain Duke Energy subsidiaries are also subsidiary registrants, including Duke Energy Carolinas; Progress Energy; Duke Energy Progress; Duke Energy Florida; Duke Energy Ohio; Duke Energy Indiana and Piedmont. When discussing Duke Energy’s consolidated financial information, it necessarily includes the results of its separate Subsidiary Registrants, which along with Duke Energy, are collectively referred to as the Duke Energy Registrants.

In October 2016, Duke Energy completed the acquisition of Piedmont. Duke Energy's consolidated financial statements include Piedmont's results of operations and cash flows activity subsequent to the acquisition date. Effective November 1, 2016, Piedmont's fiscal year-end was changed from October 31 to December 31, the year-end of Duke Energy. A transition report was filed on Form 10-Q (Form 10-QT) for the transition period from November 1, 2016, to December 31, 2016. See Note 2 for additional information regarding the acquisition.

In December 2016, Duke Energy completed an exit of the Latin American market to focus on its domestic regulated business, which was further bolstered by the acquisition of Piedmont. The sale of the International Energy business segment, excluding an equity method investment in NMC, was completed through two transactions including a sale of assets in Brazil to CTG and a sale of Duke Energy's remaining Latin American assets in Peru, Chile, Ecuador, Guatemala, El Salvador and Argentina to I Squared (collectively, the International Disposal Group). See Note 2 for additional information on the sale of International Energy.

The information in these combined notes relates to each of the Duke Energy Registrants as noted in the Index to Combined Notes to Consolidated Financial Statements. However, none of the Subsidiary Registrants make any representation as to information related solely to Duke Energy or the Subsidiary Registrants of Duke Energy other than itself.

These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of the Duke Energy Registrants and subsidiaries or VIEs where the respective Duke Energy Registrants have control. See Note 17 for additional information on VIEs. These Consolidated Financial Statements also reflect the Duke Energy Registrants’ proportionate share of certain jointly owned generation and transmission facilities. See Note 8 for additional information on joint ownership. Substantially all of the Subsidiary Registrants' operations qualify for regulatory accounting.

Duke Energy Carolinas is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. Duke Energy Carolinas is subject to the regulatory provisions of the NCUC, PSCSC, NRC and FERC.

Progress Energy is a public utility holding company, which conducts operations through its wholly owned subsidiaries, Duke Energy Progress and Duke Energy Florida. Progress Energy is subject to regulation by FERC and other regulatory agencies listed below.

Duke Energy Progress is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. Duke Energy Progress is subject to the regulatory provisions of the NCUC, PSCSC, NRC and FERC.

Duke Energy Florida is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Florida. Duke Energy Florida is subject to the regulatory provisions of the FPSC, NRC and FERC.

Duke Energy Ohio is a regulated public utility primarily engaged in the transmission and distribution of electricity in portions of Ohio and Kentucky, the generation and sale of electricity in portions of Kentucky and the transportation and sale of natural gas in portions of Ohio and Kentucky. Duke Energy Ohio conducts competitive auctions for retail electricity supply in Ohio whereby the energy price is recovered from retail customers and recorded in Operating Revenues on the Consolidated Statements of Operations and Comprehensive Income. Operations in Kentucky are conducted through its wholly owned subsidiary, Duke Energy Kentucky. References herein to Duke Energy Ohio collectively include Duke Energy Ohio and its subsidiaries, unless otherwise noted. Duke Energy Ohio is subject to the regulatory provisions of the PUCO, KPSC and FERC.

Duke Energy Indiana is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Indiana. Duke Energy Indiana is subject to the regulatory provisions of the IURC and FERC.

Piedmont is a regulated public utility primarily engaged in the distribution of natural gas in portions of North Carolina, South Carolina and Tennessee. Piedmont is subject to the regulatory provisions of the NCUC, PSCSC, TPUC and FERC.

Certain prior year amounts have been reclassified to conform to the current year presentation.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Current Assets and Liabilities

The following table provides a description of amounts included in Other within Current Assets or Current Liabilities that exceed 5 percent of total Current Assets or Current Liabilities on the Duke Energy Registrants' Consolidated Balance Sheets at either December 31, 2018, or 2017.

 

 

 

December 31,

(in millions)

Location

 

2018

 

2017

Duke Energy

 

 

 

 

 

Income taxes receivable

Current Assets

 

$

729

 

 

$

330

 

Accrued compensation

Current Liabilities

 

793

 

 

757

 

Duke Energy Carolinas

 

 

 

 

 

Accrued compensation

Current Liabilities

 

$

251

 

 

$

252

 

Progress Energy

 

 

 

 

 

Income taxes receivable

Current Assets

 

$

66

 

 

$

278

 

Customer deposits

Current Liabilities

 

345

 

 

338

 

Duke Energy Progress

 

 

 

 

 

Customer deposits

Current Liabilities

 

$

137

 

 

$

129

 

Accrued compensation

Current Liabilities

 

130

 

 

132

 

Duke Energy Florida

 

 

 

 

 

Customer deposits

Current Liabilities

 

$

208

 

 

$

208

 

Other accrued liabilities

Current Liabilities

 

85

 

 

16

 

Duke Energy Ohio

 

 

 

 

 

Income taxes receivable

Current Assets

 

$

13

 

 

$

36

 

Customer deposits

Current Liabilities

 

44

 

 

46

 

Duke Energy Indiana

 

 

 

 

 

Customer deposits

Current Liabilities

 

$

47

 

 

$

45

 

Piedmont

 

 

 

 

 

Income taxes receivable

Current Assets

 

$

11

 

 

$

43

 

Discontinued Operations

The results of operations of the International Disposal Group have been classified as Discontinued Operations on Duke Energy's Consolidated Statements of Operations. Duke Energy has elected to present cash flows of discontinued operations combined with cash flows of continuing operations. Unless otherwise noted, the notes to these consolidated financial statements exclude amounts related to discontinued operations for all periods presented. See Note 2 for additional information.

Amounts Attributable to Controlling Interests

For the years ended December 31, 2018, and 2017, the Income (Loss) From Discontinued Operations, net of tax on Duke Energy's Consolidated Statements of Operations is entirely attributable to controlling interest. For the year ended December 31, 2016, $18 million of net income is attributable to noncontrolling interests, which consisted of $7 million included in Income from Continuing Operations and $11 million included in Income (Loss) From Discontinued Operations, net of tax on Duke Energy's Consolidated Statement of Operations.

 

 

Significant Accounting Policies

Use of Estimates

In preparing financial statements that conform to GAAP, the Duke Energy Registrants must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.

Regulatory Accounting

The majority of the Duke Energy Registrants’ operations are subject to price regulation for the sale of electricity and natural gas by state utility commissions or FERC. When prices are set on the basis of specific costs of the regulated operations and an effective franchise is in place such that sufficient natural gas or electric services can be sold to recover those costs, the Duke Energy Registrants apply regulatory accounting. Regulatory accounting changes the timing of the recognition of costs or revenues relative to a company that does not apply regulatory accounting. As a result, regulatory assets and regulatory liabilities are recognized on the Consolidated Balance Sheets. Regulatory assets and liabilities are amortized consistent with the treatment of the related cost in the ratemaking process. See Note 4 for further information.

Regulatory accounting rules also require recognition of a disallowance (also called "impairment") loss if it becomes probable that part of the cost of a plant under construction (or a recently completed plant or an abandoned plant) will be disallowed for ratemaking purposes and a reasonable estimate of the amount of the disallowance can be made. For example, if a cost cap is set for a plant still under construction, the amount of the disallowance is a result of a judgment as to the ultimate cost of the plant. These disallowances can require judgments on allowed future rate recovery.

When it becomes probable that regulated generation, transmission or distribution assets will be abandoned, the cost of the asset is removed from plant in service. The value that may be retained as a regulatory asset on the balance sheet for the abandoned property is dependent upon amounts that may be recovered through regulated rates, including any return. As such, an impairment charge could be partially or fully offset by the establishment of a regulatory asset if rate recovery is probable. The impairment charge for a disallowance of costs for regulated plants under construction, recently completed or abandoned is based on discounted cash flows.

The Duke Energy Registrants utilize cost-tracking mechanisms, commonly referred to as fuel adjustment clauses or PGA clauses. These clauses allow for the recovery of fuel and fuel-related costs, portions of purchased power, natural gas costs and hedging costs through surcharges on customer rates. The difference between the costs incurred and the surcharge revenues is recorded either as an adjustment to Operating Revenues, Operating Expenses – Fuel used in electric generation or Operating Expenses – Cost of natural gas on the Consolidated Statements of Operations, with an off-setting impact on regulatory assets or liabilities.

Cash, Cash Equivalents and Restricted Cash

All highly liquid investments with maturities of three months or less at the date of acquisition are considered cash equivalents. Duke Energy, Progress Energy and Duke Energy Florida have restricted cash balances related primarily to collateral assets, escrow deposits and VIEs. See Note 17 for additional information. Restricted cash amounts are included in Other within Current Assets and Other Noncurrent Assets on the Consolidated Balance Sheets. The following table presents the components of cash, cash equivalents and restricted cash included in the Consolidated Balance Sheets.

 

December 31, 2018

 

December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

Progress

Energy

 

Duke

Progress

Energy

 

Energy

Energy

Florida

 

Energy

Energy

Florida

Current Assets

 

 

 

 

 

 

 

Cash and cash equivalents

$

442

 

$

67

 

$

36

 

 

$

358

 

$

40

 

$

13

 

Other

141

 

39

 

39

 

 

138

 

40

 

40

 

Other Noncurrent Assets

 

 

 

 

 

 

 

Other

8

 

6

 

 

 

9

 

7

 

 

Total cash, cash equivalents and restricted cash

$

591

 

$

112

 

$

75

 

 

$

505

 

$

87

 

$

53

 

 

Inventory

Inventory is used for operations and is recorded primarily using the average cost method. Inventory related to regulated operations is valued at historical cost. Inventory related to nonregulated operations is valued at the lower of cost or market. Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to property, plant and equipment when installed. Inventory, including excess or obsolete inventory, is written-down to the lower of cost or market value. Once inventory has been written-down, it creates a new cost basis for the inventory that is not subsequently written-up. Provisions for inventory write-offs were not material at December 31, 2018, and 2017. The components of inventory are presented in the tables below.

 

December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Materials and supplies

$

2,238

 

 

$

731

 

 

$

1,049

 

 

$

734

 

 

$

315

 

 

$

84

 

 

$

312

 

 

$

2

 

Coal

491

 

 

175

 

 

192

 

 

106

 

 

86

 

 

14

 

 

109

 

 

 

Natural gas, oil and other

355

 

 

42

 

 

218

 

 

114

 

 

103

 

 

28

 

 

1

 

 

68

 

Total inventory

$

3,084

 

 

$

948

 

 

$

1,459

 

 

$

954

 

 

$

504

 

 

$

126

 

 

$

422

 

 

$

70

 

 

 

December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Materials and supplies

$

2,293

 

 

$

744

 

 

$

1,118

 

 

$

774

 

 

$

343

 

 

$

82

 

 

$

309

 

 

$

2

 

Coal

603

 

 

192

 

 

255

 

 

139

 

 

116

 

 

17

 

 

139

 

 

 

Natural gas, oil and other

354

 

 

35

 

 

219

 

 

104

 

 

115

 

 

34

 

 

2

 

 

64

 

Total inventory

$

3,250

 

 

$

971

 

 

$

1,592

 

 

$

1,017

 

 

$

574

 

 

$

133

 

 

$

450

 

 

$

66

 

Investments in Debt and Equity Securities

The Duke Energy Registrants classify investments in equity securities as FV-NI and investments in debt securities as AFS. Both categories are recorded at fair value on the Consolidated Balance Sheets. Realized and unrealized gains and losses on securities classified as FV-NI are reported through net income. Unrealized gains and losses for debt securities classified as AFS are included in AOCI until realized, except OTTIs that are included in earnings immediately. At the time gains and losses for debt securities are realized, they are reported through net income. For certain investments of regulated operations, such as substantially all of the NDTF, realized and unrealized gains and losses (including any OTTIs) on debt securities are recorded as a regulatory asset or liability. The credit loss portion of debt securities of nonregulated operations are included in earnings. Investments in debt and equity securities are classified as either current or noncurrent based on management’s intent and ability to sell these securities, taking into consideration current market liquidity. See Note 15 for further information.

Goodwill and Intangible Assets

Goodwill

Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont perform annual goodwill impairment tests as of August 31 each year at the reporting unit level, which is determined to be a business segment or one level below. Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont update these tests between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 11 for further information.

 

Intangible Assets

Intangible assets are included in Other in Other Noncurrent Assets on the Consolidated Balance Sheets. Generally, intangible assets are amortized using an amortization method that reflects the pattern in which the economic benefits of the intangible asset are consumed or on a straight-line basis if that pattern is not readily determinable. Amortization of intangibles is reflected in Depreciation and amortization on the Consolidated Statements of Operations. Intangible assets are subject to impairment testing and if impaired, the carrying value is accordingly reduced.

Emission allowances permit the holder of the allowance to emit certain gaseous byproducts of fossil fuel combustion, including SO2 and NOX. Allowances are issued by the EPA at zero cost and may also be bought and sold via third-party transactions. Allowances allocated to or acquired by the Duke Energy Registrants are held primarily for consumption. Carrying amounts for emission allowances are based on the cost to acquire the allowances or, in the case of a business combination, on the fair value assigned in the allocation of the purchase price of the acquired business. Emission allowances are expensed to Fuel used in electric generation and purchased power on the Consolidated Statements of Operations.

RECs are used to measure compliance with renewable energy standards and are held primarily for consumption. See Note 11 for further information.

Long-Lived Asset Impairments

The Duke Energy Registrants evaluate long-lived assets, excluding goodwill, for impairment when circumstances indicate the carrying value of those assets may not be recoverable. An impairment exists when a long-lived asset’s carrying value exceeds the estimated undiscounted cash flows expected to result from the use and eventual disposition of the asset. The estimated cash flows may be based on alternative expected outcomes that are probability weighted. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the carrying value of the asset is written-down to its then-current estimated fair value and an impairment charge is recognized.

The Duke Energy Registrants assess fair value of long-lived assets using various methods, including recent comparable third-party sales, internally developed discounted cash flow analysis and analysis from outside advisors. Triggering events to reassess cash flows may include, but are not limited to, significant changes in commodity prices, the condition of an asset or management’s interest in selling the asset.

Equity Method Investment Impairments

Investments in affiliates that are not controlled by Duke Energy, but over which it has significant influence, are accounted for using the equity method. Equity method investments are assessed for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. If the decline in value is considered to be other than temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment.

Impairment assessments use a discounted cash flow income approach and include consideration of the severity and duration of any decline in the fair value of the investments. The estimated cash flows may be based on alternative expected outcomes that are probability weighted. Key inputs that involve estimates and significant management judgment include cash flow projections, selection of a discount rate, probability weighting of potential outcomes, and whether any decline in value is considered temporary.

 

 

 

 

 

 

 

 

 

 

 

Property, Plant and Equipment

Property, plant and equipment are stated at the lower of depreciated historical cost net of any disallowances or fair value, if impaired. The Duke Energy Registrants capitalize all construction-related direct labor and material costs, as well as indirect construction costs such as general engineering, taxes and financing costs. See “Allowance for Funds Used During Construction and Interest Capitalized” for information on capitalized financing costs. Costs of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of the asset, are expensed as incurred. Depreciation is generally computed over the estimated useful life of the asset using the composite straight-line method. Depreciation studies are conducted periodically to update composite rates and are approved by state utility commissions and/or the FERC when required. The composite weighted average depreciation rates, excluding nuclear fuel, are included in the table that follows.

 

Years Ended December 31,

 

2018

 

2017

 

2016

Duke Energy

3.0

%

 

2.8

%

 

2.8

%

Duke Energy Carolinas

2.8

%

 

2.8

%

 

2.8

%

Progress Energy

2.9

%

 

2.6

%

 

2.7

%

Duke Energy Progress

2.9

%

 

2.6

%

 

2.6

%

Duke Energy Florida

3.0

%

 

2.8

%

 

2.8

%

Duke Energy Ohio

2.8

%

 

2.8

%

 

2.6

%

Duke Energy Indiana

3.3

%

 

3.0

%

 

3.1

%

Piedmont(a)

2.5

%

 

2.3

%

 

 

(a) Piedmont's weighted average depreciation rate was 2.4 percent for the annualized two months ended December 31, 2016, and for the year ended October 31, 2016.

In general, when the Duke Energy Registrants retire regulated property, plant and equipment, the original cost plus the cost of retirement, less salvage value and any depreciation already recognized, is charged to accumulated depreciation. However, when it becomes probable the asset will be retired substantially in advance of its original expected useful life or is abandoned, the cost of the asset and the corresponding accumulated depreciation is recognized as a separate asset. If the asset is still in operation, the net amount is classified as Generation facilities to be retired, net on the Consolidated Balance Sheets. If the asset is no longer operating, the net amount is classified in Regulatory assets on the Consolidated Balance Sheets if deemed recoverable (see discussion of long-lived asset impairments above). When it becomes probable an asset will be abandoned, the cost of the asset and accumulated depreciation is reclassified to Regulatory assets on the Consolidated Balance Sheets for amounts recoverable in rates. The carrying value of the asset is based on historical cost if the Duke Energy Registrants are allowed to recover the remaining net book value and a return equal to at least the incremental borrowing rate. If not, an impairment is recognized to the extent the net book value of the asset exceeds the present value of future revenues discounted at the incremental borrowing rate.

When the Duke Energy Registrants sell entire regulated operating units, or retire or sell nonregulated properties, the original cost and accumulated depreciation and amortization balances are removed from Property, Plant and Equipment on the Consolidated Balance Sheets. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body. See Note 10 for additional information.

Nuclear Fuel

Nuclear fuel is classified as Property, Plant and Equipment on the Consolidated Balance Sheets.

Nuclear fuel in the front-end fuel processing phase is considered work in progress and not amortized until placed in service. Amortization of nuclear fuel is included within Fuel used in electric generation and purchased power on the Consolidated Statements of Operations. Amortization is recorded using the units-of-production method.

 

 

 

Allowance for Funds Used During Construction and Interest Capitalized

For regulated operations, the debt and equity costs of financing the construction of property, plant and equipment are reflected as AFUDC and capitalized as a component of the cost of property, plant and equipment. AFUDC equity is reported on the Consolidated Statements of Operations as non-cash income in Other income and expenses, net. AFUDC debt is reported as a non-cash offset to Interest Expense. After construction is completed, the Duke Energy Registrants are permitted to recover these costs through their inclusion in rate base and the corresponding subsequent depreciation or amortization of those regulated assets.

AFUDC equity, a permanent difference for income taxes, reduces the ETR when capitalized and increases the ETR when depreciated or amortized. See Note 23 for additional information.

For nonregulated operations, interest is capitalized during the construction phase with an offsetting non-cash credit to Interest Expense on the Consolidated Statements of Operations.

Asset Retirement Obligations

AROs are recognized for legal obligations associated with the retirement of property, plant and equipment. Substantially all AROs are related to regulated operations. When recording an ARO, the present value of the projected liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The liability is accreted over time. For operating plants, the present value of the liability is added to the cost of the associated asset and depreciated over the remaining life of the asset. For retired plants, the present value of the liability is recorded as a regulatory asset unless determined not to be probable of recovery.

The present value of the initial obligation and subsequent updates are based on discounted cash flows, which include estimates regarding timing of future cash flows, selection of discount rates and cost escalation rates, among other factors. These estimates are subject to change. Depreciation expense is adjusted prospectively for any changes to the carrying amount of the associated asset. The Duke Energy Registrants receive amounts to fund the cost of the ARO for regulated operations through a combination of regulated revenues and earnings on the NDTF. As a result, amounts recovered in regulated revenues, earnings on the NDTF, accretion expense and depreciation of the associated asset are netted and deferred as a regulatory asset or liability.

Obligations for nuclear decommissioning are based on site-specific cost studies. Duke Energy Carolinas and Duke Energy Progress assume prompt dismantlement of the nuclear facilities after operations are ceased. Duke Energy Florida assumes Crystal River Unit 3 will be placed into a safe storage configuration until eventual dismantlement is completed by 2074. Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida also assume that spent fuel will be stored on-site until such time that it can be transferred to a yet to be built DOE facility.

Obligations for closure of ash basins are based upon discounted cash flows of estimated costs for site-specific plans, if known, or probability weightings of the potential closure methods if the closure plans are under development and multiple closure options are being considered and evaluated on a site-by-site basis. See Note 9 for additional information.

Revenue Recognition

Duke Energy recognizes revenue as customers obtain control of promised goods and services in an amount that reflects consideration expected in exchange for those goods or services. Generally, the delivery of electricity and natural gas results in the transfer of control to customers at the time the commodity is delivered and the amount of revenue recognized is equal to the amount billed to each customer, including estimated volumes delivered when billings have not yet occurred. See Note 18 for further information.

Derivatives and Hedging

Derivative and non-derivative instruments may be used in connection with commodity price and interest rate activities, including swaps, futures, forwards and options. All derivative instruments, except those that qualify for the NPNS exception, are recorded on the Consolidated Balance Sheets at fair value. Qualifying derivative instruments may be designated as either cash flow hedges or fair value hedges. Other derivative instruments (undesignated contracts) either have not been designated or do not qualify as hedges. The effective portion of the change in the fair value of cash flow hedges is recorded in AOCI. The effective portion of the change in the fair value of a fair value hedge is offset in net income by changes in the hedged item. For activity subject to regulatory accounting, gains and losses on derivative contracts are reflected as regulatory assets or liabilities and not as other comprehensive income or current period income. As a result, changes in fair value of these derivatives have no immediate earnings impact.

 

 

Formal documentation, including transaction type and risk management strategy, is maintained for all contracts accounted for as a hedge. At inception and at least every three months thereafter, the hedge contract is assessed to see if it is highly effective in offsetting changes in cash flows or fair values of hedged items.

See Note 14 for further information.

Captive Insurance Reserves

Duke Energy has captive insurance subsidiaries that provide coverage, on an indemnity basis, to the Subsidiary Registrants as well as certain third parties, on a limited basis, for financial losses, primarily related to property, workers’ compensation and general liability. Liabilities include provisions for estimated losses IBNR, as well as estimated provisions for known claims. IBNR reserve estimates are primarily based upon historical loss experience, industry data and other actuarial assumptions. Reserve estimates are adjusted in future periods as actual losses differ from experience.

Duke Energy, through its captive insurance entities, also has reinsurance coverage with third parties for certain losses above a per occurrence and/or aggregate retention. Receivables for reinsurance coverage are recognized when realization is deemed probable.

Unamortized Debt Premium, Discount and Expense

Premiums, discounts and expenses incurred with the issuance of outstanding long-term debt are amortized over the term of the debt issue. The gain or loss on extinguishment associated with refinancing higher-cost debt obligations in the regulated operations is amortized. Amortization expense is recorded as Interest Expense in the Consolidated Statements of Operations and is reflected as Depreciation, amortization and accretion within Net cash provided by operating activities on the Consolidated Statements of Cash Flows.

Premiums, discounts and expenses are presented as an adjustment to the carrying value of the debt amount and included in Long-Term Debt on the Consolidated Balance Sheets presented.

Loss Contingencies and Environmental Liabilities

Contingent losses are recorded when it is probable a loss has occurred and can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, the minimum amount in the range is recorded. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Environmental liabilities are recorded on an undiscounted basis when environmental remediation or other liabilities become probable and can be reasonably estimated. Environmental expenditures related to past operations that do not generate current or future revenues are expensed. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Certain environmental expenditures receive regulatory accounting treatment and are recorded as regulatory assets.

See Notes 4 and 5 for further information.

Pension and Other Post-Retirement Benefit Plans

Duke Energy maintains qualified, non-qualified and other post-retirement benefit plans. Eligible employees of the Subsidiary Registrants participate in the respective qualified, non-qualified and other post-retirement benefit plans and the Subsidiary Registrants are allocated their proportionate share of benefit costs. See Note 22 for further information, including significant accounting policies associated with these plans.

Severance and Special Termination Benefits

Duke Energy has severance plans under which in general, the longer a terminated employee worked prior to termination the greater the amount of severance benefits. A liability for involuntary severance is recorded once an involuntary severance plan is committed to by management if involuntary severances are probable and can be reasonably estimated. For involuntary severance benefits incremental to its ongoing severance plan benefits, the fair value of the obligation is expensed at the communication date if there are no future service requirements or over the required future service period. Duke Energy also offers special termination benefits under voluntary severance programs. Special termination benefits are recorded immediately upon employee acceptance absent a significant retention period. Otherwise, the cost is recorded over the remaining service period. Employee acceptance of voluntary severance benefits is determined by management based on the facts and circumstances of the benefits being offered. See Note 20 for further information.

 

 

Guarantees

If necessary, liabilities are recognized at the time of issuance or material modification of a guarantee for the estimated fair value of the obligation it assumes. Fair value is estimated using a probability-weighted approach. The obligation is reduced over the term of the guarantee or related contract in a systematic and rational method as risk is reduced. Any additional contingent loss for guarantee contracts subsequent to the initial recognition of a liability is accounted for and recognized at the time a loss is probable and can be reasonably estimated. See Note 7 for further information.

Stock-Based Compensation

Stock-based compensation represents costs related to stock-based awards granted to employees and Board of Directors members. Duke Energy recognizes stock-based compensation based upon the estimated fair value of awards, net of estimated forfeitures at the date of issuance. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period. Compensation cost is recognized as expense or capitalized as a component of property, plant and equipment. See Note 21 for further information.

Income Taxes

Duke Energy and its subsidiaries file a consolidated federal income tax return and other state and foreign jurisdictional returns. The Subsidiary Registrants are parties to a tax-sharing agreement with Duke Energy. Income taxes recorded represent amounts the Subsidiary Registrants would incur as separate C-Corporations. Deferred income taxes have been provided for temporary differences between GAAP and tax bases of assets and liabilities because the differences create taxable or tax-deductible amounts for future periods. ITCs associated with regulated operations are deferred and amortized as a reduction of income tax expense over the estimated useful lives of the related properties.

Accumulated deferred income taxes are valued using the enacted tax rate expected to apply to taxable income in the periods in which the deferred tax asset or liability is expected to be settled or realized. In the event of a change in tax rates, deferred tax assets and liabilities are remeasured as of the enactment date of the new rate. To the extent that the change in the value of the deferred tax represents an obligation to customers, the impact of the remeasurement is deferred to a regulatory liability. Remaining impacts are recorded in income from continuing operations. If Duke Energy's estimate of the tax effect of reversing temporary differences is not reflective of actual outcomes, is modified to reflect new developments or interpretations of the tax law, revised to incorporate new accounting principles, or changes in the expected timing or manner of the reversal then Duke Energy's results of operations could be impacted.

Tax-related interest and penalties are recorded in Interest Expense and Other Income and Expenses, net in the Consolidated Statements of Operations.

See Note 23 for further information.

Accounting for Renewable Energy Tax Credits

When Duke Energy receives ITCs on wind or solar facilities, it reduces the basis of the property recorded on the Consolidated Balance Sheets by the amount of the ITC and, therefore, the ITC benefit is ultimately recognized in the statement of operations through reduced depreciation expense. Additionally, certain tax credits and government grants result in an initial tax depreciable base in excess of the book carrying value by an amount equal to one half of the ITC. Deferred tax benefits are recorded as a reduction to income tax expense in the period that the basis difference is created.

 

 

 

 

 

 

 

 

 

Excise Taxes

Certain excise taxes levied by state or local governments are required to be paid even if not collected from the customer. These taxes are recognized on a gross basis. Otherwise, the taxes are accounted for net. Excise taxes accounted for on a gross basis within both Operating Revenues and Property and other taxes in the Consolidated Statements of Operations were as follows.

 

Years Ended December 31,

(in millions)

2018

 

2017

 

2016

Duke Energy

$

405

 

 

$

376

 

 

$

362

 

Duke Energy Carolinas

35

 

 

36

 

 

31

 

Progress Energy

241

 

 

220

 

 

213

 

Duke Energy Progress

19

 

 

19

 

 

18

 

Duke Energy Florida

222

 

 

201

 

 

195

 

Duke Energy Ohio

105

 

 

98

 

 

100

 

Duke Energy Indiana

22

 

 

20

 

 

17

 

Piedmont(a)

2

 

 

2

 

 

 

(a) Piedmont's excise taxes were immaterial for the two months ended December 31, 2016, and $2 million for the year ended October 31, 2016.

Dividend Restrictions and Unappropriated Retained Earnings

Duke Energy does not have any legal, regulatory or other restrictions on paying common stock dividends to shareholders. However, as further described in Note 4, due to conditions established by regulators in conjunction with merger transaction approvals, Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio, Duke Energy Indiana and Piedmont have restrictions on paying dividends or otherwise advancing funds to Duke Energy. At December 31, 2018, and 2017, an insignificant amount of Duke Energy’s consolidated Retained earnings balance represents undistributed earnings of equity method investments.

New Accounting Standards

The new accounting standards adopted for 2018 and 2017 had no material impact on the presentation or results of operations, cash flows or financial position of the Duke Energy Registrants. The following accounting standards were adopted by the Duke Energy Registrants during 2018.

Revenue from Contracts with Customers. In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. The core principle of this guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration expected in exchange for those goods or services. The amendments also required disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The majority of Duke Energy’s revenue is in scope of the new guidance. Other revenue arrangements, such as alternative revenue programs and certain PPAs and lighting agreements accounted for as leases, are excluded from the scope of this guidance and, therefore, are accounted for and evaluated for separate presentation and disclosure under other relevant accounting guidance.

Duke Energy elected the modified retrospective method of adoption effective January 1, 2018. Under the modified retrospective method of adoption, prior year reported results are not restated. Adoption of this standard did not result in a material change in the timing or pattern of revenue recognition and a cumulative-effect adjustment was not recorded at January 1, 2018. Duke Energy utilized certain practical expedients including applying this guidance to open contracts at the date of adoption, expensing costs to obtain a contract where the amortization period of the asset would have been one year or less, ignoring the effects of a significant financing when the period between transfer of the good or service and payment is one year or less and recognizing revenues for certain contracts under the invoice practical expedient, which allows revenue recognition to be consistent with invoiced amounts (including unbilled estimates) provided certain criteria are met, including consideration of whether the invoiced amounts reasonably represent the value provided to customers.

In preparation for adoption, Duke Energy identified material revenue streams and reviewed representative contracts and tariffs, including those associated with certain long-term customer contracts such as wholesale contracts, PPAs and other customer arrangements. Duke Energy also monitored the activities of the power and utilities industry revenue recognition task force and has reviewed published positions on specific industry issues to evaluate the impact, if any, on Duke Energy’s specific contracts and conclusions. Duke Energy applied the available practical expedient to portfolios of tariffs and contracts with similar characteristics. The vast majority of sales, including energy provided to retail customers, are from tariff offerings that provide natural gas or electricity without a defined contractual term ("at-will"). In most circumstances, revenue from contracts with customers is equivalent to the electricity or natural gas supplied and billed in that period (including unbilled estimates). As such, adoption of the new rules did not result in a shift in the timing or pattern of revenue recognition for such sales. While there have been changes to the captions and descriptions of revenues in Duke Energy’s financial statements, the most significant impact as a result of adopting the standard are additional disclosures around the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. See Note 18 for further information.

Financial Instruments Classification and Measurement. On January 1, 2018, Duke Energy adopted FASB guidance, which revised the classification and measurement of certain financial instruments. The adopted guidance changes the presentation of realized and unrealized gains and losses in certain equity securities that were previously recorded in AOCI. These gains and losses are now recorded in net income. An entity's equity investments that are accounted for under the equity method of accounting are not included within the scope of the new guidance. This guidance had a minimal impact on the Duke Energy Registrant's Consolidated Statements of Operations and Comprehensive Income as changes in the fair value of most of the Duke Energy Registrants' equity securities are deferred as regulatory assets or liabilities pursuant to accounting guidance for regulated operations. The resulting adjustment of unrealized gains and losses in AOCI to retained earnings was immaterial. The primary impact to Duke Energy as a result of implementing this guidance is adding disclosure requirements to present separately the financial assets and financial liabilities by measurement category and form of financial asset. See Notes 15 and 16 for further information.

Statement of Cash Flows. In November 2016, the FASB issued revised accounting guidance to reduce diversity in practice for the presentation and classification of restricted cash on the Consolidated Statements of Cash Flows. Under the updated guidance, restricted cash and restricted cash equivalents are included within beginning-of-period and end-of-period cash and cash equivalents on the Consolidated Statements of Cash Flows. Duke Energy adopted this guidance on January 1, 2018. The guidance has been applied using a retrospective transition method to each period presented. The adoption by Duke Energy of the revised guidance resulted in a change to the amount of Cash, cash equivalents and restricted cash explained when reconciling the beginning-of-period and end-of-period total amounts shown on the Consolidated Statements of Cash Flows. In addition, a reconciliation has been provided of Cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sums to the total of the same such amounts in the Consolidated Statements of Cash Flows. Prior to adoption, the Duke Energy Registrants reflected changes in noncurrent restricted cash within Cash Flows from Investing Activities and changes in current restricted cash within Cash Flows from Operating Activities on the Consolidated Statements of Cash Flows.

In August 2016, the FASB issued accounting guidance addressing diversity in practice for eight separate cash flow issues. The guidance requires entities to classify distributions received from equity method investees using either the cumulative earnings approach or the nature of the distribution approach. Duke Energy adopted this guidance on January 1, 2018, and elected the nature of distribution approach. This approach requires all distributions received to be categorized based on legal documentation describing the nature of the activities generating the distribution. Cash inflows resulting in a return on investment (surplus) will be reflected in Cash Flows from Operating Activities on the Consolidated Statements of Cash Flows, whereas cash inflows resulting in a return of investment (capital) will be reflected in Cash Flows from Investing Activities on the Consolidated Statements of Cash Flows. The guidance has been applied using the retrospective transition method to each period presented. There are no changes to the Consolidated Statements of Cash Flows for the periods presented as a result of this accounting change.

Retirement Benefits. In March 2017, the FASB issued revised accounting guidance for the presentation of net periodic costs related to benefit plans. Previous guidance required the aggregation of all the components of net periodic costs on the Consolidated Statements of Operations and did not require the disclosure of the location of net periodic costs on the Consolidated Statements of Operations. Under the amended guidance, the service cost component of net periodic costs is included within Operating Income within the same line as other compensation expenses. All other components of net periodic costs are outside of Operating Income. In addition, the updated guidance permits only the service cost component of net periodic costs to be capitalized to Inventory or Property, Plant and Equipment. This represents a change from previous guidance, which permitted all components of net periodic costs to be eligible for capitalization.

Duke Energy adopted this guidance on January 1, 2018. Under previous guidance, Duke Energy presented the total non-capitalized net periodic costs within Operation, maintenance and other on the Consolidated Statements of Operations. The adoption of this guidance resulted in a retrospective change to reclassify the presentation of the non-service cost (benefit) components of net periodic costs to Other income and expenses. Duke Energy utilized the practical expedient for retrospective presentation. The change in components of net periodic costs eligible for capitalization is applicable prospectively. Since Duke Energy’s service cost component is greater than the total net periodic costs, the change results in increased capitalization of net periodic costs, higher Operation, maintenance and other and higher Other income and expenses. The resulting prospective impact to Duke Energy is an immaterial increase in Net Income. See Note 22 for further information.

For Duke Energy, the retrospective change resulted in higher Operation, maintenance and other and higher Other income and expenses, net, of $156 million and $139 million for the years ended December 31, 2017, and 2016, respectively. There was no change to Net Income for these prior periods.

The following new accounting standards have been issued, but have not yet been adopted by the Duke Energy Registrants, as of December 31, 2018.

Leases. In February 2016, the FASB issued revised accounting guidance for leases. The core principle of this guidance is that a lessee should recognize the assets and liabilities that arise from leases on the balance sheet.

For Duke Energy, this guidance is effective for interim and annual periods beginning January 1, 2019. The guidance will be applied using a modified retrospective approach. Under the modified retrospective approach of adoption, prior year reported results are not restated and a cumulative-effect adjustment, if applicable, is recorded to retained earnings at January 1, 2019. Upon adoption, agreements considered leases for the use of certain aircraft, space on communication towers, industrial equipment, fleet vehicles, fuel transportation (barges and railcars), land and office space will be recognized on the balance sheet. Duke Energy expects to adopt the following practical expedients:

 

Practical Expedient

Description

Election

Package of transition practical expedients (for leases commenced prior to adoption date and must be adopted as a package)

Do not need to 1) reassess whether any expired or existing contracts are/or contain leases, 2) reassess the lease classification for any expired or existing leases and 3) reassess initial direct costs for any existing leases.

Duke Energy plans to elect this practical expedient.

Short-term lease expedient (elect by class of underlying asset)

Elect as an accounting policy to not apply the recognition requirements to short-term leases by asset class.

Duke Energy plans to elect this practical expedient for all asset classes.

Lease and non-lease components (elect by class of underlying asset)

Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component by asset class.

Duke Energy plans to elect this practical expedient for all asset classes.

Hindsight expedient (when determining lease term)

Elect to use hindsight to determine the lease term.

Duke Energy plans to elect this practical expedient.

Existing and expired land easements not previously accounted for as leases

Elect to not evaluate existing or expired easements under the new guidance and carry forward current accounting treatment.

Duke Energy plans to elect this practical expedient.

Comparative reporting requirements for initial adoption

 

Elect to apply transition requirements at adoption date, recognize cumulative effect adjustment to retained earnings in period of adoption and not apply ASC 842 to comparative periods, including disclosures.

Duke Energy plans to elect this practical expedient.

Lessor expedient (elect by class of underlying asset)

 

Elect as an accounting policy to aggregate non-lease components with the related lease component when specified conditions are met by asset class. Account for the combined component based on its predominant characteristic (revenue or operating lease).

Duke Energy plans to elect this practical expedient for all asset classes.

 

 

Duke Energy currently expects to record right-of-use assets and operating lease liabilities on its balance sheet as shown in approximate amounts in the table below:

 

(in millions)

Duke Energy

$

1,700

 

Duke Energy Carolinas

150

 

Progress Energy

850

 

Duke Energy Progress

400

 

Duke Energy Florida

450

 

Duke Energy Ohio

25

 

Duke Energy Indiana

60

 

Piedmont

30

 

In addition to the recognition of operating leases on the balance sheet, Duke Energy expects additional disclosures including both finance and operating lease costs, short-term lease costs, variable lease costs, weighted-average remaining lease term as well as weighted-average discount rates. Duke Energy does not expect a material change to its financial statements from adoption of the new standard for contracts where it is the lessor.

 

2. ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS

The Duke Energy Registrants consolidate assets and liabilities from acquisitions as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date.

2016 Acquisition of Piedmont Natural Gas

On October 3, 2016, Duke Energy acquired all outstanding common stock of Piedmont for a total cash purchase price of $5.0 billion and assumed Piedmont's existing long-term debt, which had a fair value of approximately $2.0 billion at the time of the acquisition. The acquisition provides a foundation for Duke Energy to establish a broader, long-term strategic natural gas infrastructure platform to complement its existing natural gas pipeline investments and regulated natural gas business in the Midwest. In connection with the closing of the acquisition, Piedmont became a wholly owned subsidiary of Duke Energy.

Accounting Charges Related to the Acquisition

Duke Energy incurred pretax transaction and integration costs associated with the acquisition of $84 million, $103 million and $439 million for the years ended December 31, 2018, 2017 and 2016, respectively. Amounts recorded on the Consolidated Statements of Operations in 2018 and 2017 were primarily system integration costs of $78 million and $71 million, respectively, related to combining the various operational and financial systems of Duke Energy and Piedmont, including a one-time software impairment resulting from planned accounting system and process integration in 2017. A $7 million charge was recorded within Impairment Charges, with the remaining $64 million recorded within Operation, maintenance and other in 2017.

Amounts recorded in 2016 include:

  • Interest expense of $234 million related to the acquisition financing, including realized losses on forward-starting interest rate swaps of $190 million. See Note 14 for additional information on the swaps.

  • Charges of $104 million related to commitments made in conjunction with the transaction, including charitable contributions and a one-time bill credit to Piedmont customers. $10 million was recorded as a reduction in Operating Revenues, with the remaining $94 million recorded within Operation, maintenance and other.

  • Other transaction and integration costs of $101 million recorded to Operation, maintenance and other, including professional fees and severance charges.

The majority of transition and integration activities were completed by the end of 2018.

 

Pro Forma Financial Information

The following unaudited pro forma financial information reflects the combined results of operations of Duke Energy and Piedmont as if the merger had occurred as of January 1, 2015. The pro forma financial information does not include potential cost savings, intercompany revenues, Piedmont’s earnings from a certain equity method investment sold immediately prior to the merger or non-recurring transaction and integration costs incurred by Duke Energy and Piedmont. The after-tax transaction and integration costs incurred by Duke Energy and Piedmont were $279 million for the year ended December 31, 2016.

This information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of Duke Energy.

 

Year Ended December 31,

(in millions)

2016

Operating Revenues

$

23,504

 

Net Income Attributable to Duke Energy Corporation

2,442

 

Piedmont's Earnings

Piedmont's revenues and net income included in Duke Energy's Consolidated Statements of Operations for the year ended December 31, 2016, were $367 million and $20 million, respectively. Piedmont's revenues and net income for the year ended December 31, 2016, include the impact of non-recurring transaction costs of $10 million and $46 million, respectively.

DISPOSITIONS

For the years ended December 31, 2018, and 2017, the Income (Loss) from Discontinued Operations, net of tax, was immaterial. The following table summarizes the Loss from Discontinued Operations, net of tax recorded on Duke Energy's Consolidated Statements of Operations for the year ended December 31, 2016:

 

Year Ended December 31,

(in millions)

2016

International Disposal Group

$

(534

)

Other(a)

126

 

Loss from Discontinued Operations, net of tax

$

(408

)

  1. Amount represents an income tax benefit resulting from immaterial out of period deferred tax liability adjustments for previously sold businesses not related to the International Disposal Group.

2016 Sale of International Energy

In February 2016, Duke Energy announced it had initiated a process to divest the International Disposal Group, and in October 2016, announced it had entered into two separate purchase and sale agreements to execute the divestiture. Both sales closed in December of 2016, resulting in available cash proceeds of $1.9 billion, excluding transaction costs. Proceeds were primarily used to reduce the Parent debt. Existing favorable tax attributes result in no immediate U.S. federal-level cash tax impacts. Details of each transaction are as follows:

  • On December 20, 2016, Duke Energy closed on the sale of its ownership interests in businesses in Argentina, Chile, Ecuador, El Salvador, Guatemala and Peru to I Squared Capital. The assets sold included approximately 2,230 MW of hydroelectric and natural gas generation capacity, transmission infrastructure and natural gas processing facilities. I Squared Capital purchased the businesses for an enterprise value of $1.2 billion.

  • On December 29, 2016, Duke Energy closed on the sale of its Brazilian business, which included approximately 2,090 MW of hydroelectric generation capacity, to CTG for an enterprise value of $1.2 billion. With the closing of the CTG deal, Duke Energy finalized its exit from the Latin American market.

 

 

Assets Held For Sale and Discontinued Operations

As a result of the transactions, the International Disposal Group was classified as held for sale and as discontinued operations in the fourth quarter of 2016. Interest expense directly associated with the International Disposal Group was allocated to discontinued operations. No interest from corporate level debt was allocated to discontinued operations.

The following table presents the results of the International Disposal Group for the year ended December 31, 2016, which are included in Loss from Discontinued Operations, net of tax in Duke Energy's Consolidated Statements of Operations.

 

Year Ended December 31,

(in millions)

2016

Operating Revenues

$

988

 

Fuel used in electric generation and purchased power

227

 

Cost of natural gas

43

 

Operation, maintenance and other

341

 

Depreciation and amortization(a)

62

 

Property and other taxes

15

 

Impairment charges (b)

194

 

(Losses) Gains on Sales of Other Assets and Other, net

(3

)

Other Income and Expenses, net

58

 

Interest Expense

82

 

Pretax loss on disposal(c)

(514

)

Loss before income taxes(d)

(435

)

Income tax expense(e)(f)

99

 

Loss from discontinued operations of the International Disposal Group

$

(534

)

(a) Upon meeting the criteria for assets held for sale, beginning in the fourth quarter of 2016 depreciation expense ceased.

(b) In conjunction with the advancements of marketing efforts during 2016, Duke Energy performed recoverability tests of the long-lived asset groups of International Energy. As a result, Duke Energy determined the carrying value of certain assets in Central America was not fully recoverable and recorded a pretax impairment charge of $194 million. The charge represents the excess of carrying value over the estimated fair value of the assets, which was based on a Level 3 Fair Value measurement that was primarily determined from the income approach using discounted cash flows but also considered market information obtained in 2016.

(c) The pretax loss on disposal includes the recognition of cumulative foreign currency translation losses of $620 million as of the disposal date. See the Consolidated Statements of Changes in Equity for additional information.

(d) Pretax Loss attributable to Duke Energy Corporation was $(445) million for the year ended December 31, 2016.

(e) Amount includes $126 million of income tax expense on the disposal, which primarily reflects in-country taxes incurred as a result of the sale. The after-tax loss on disposal was $640 million.

(f) Amount includes an income tax benefit of $95 million. See Note 23, "Income Taxes," for additional information.

Duke Energy has elected not to separately disclose discontinued operations on the Consolidated Statements of Cash Flows. The following table summarizes Duke Energy's cash flows from discontinued operations related to the International Disposal Group.

 

Year Ended December 31,

(in millions)

2016

Cash flows provided by (used in):

 

Operating activities

$

204

 

Investing activities

(434

)

 

Other Sale Related Matters

During 2017, Duke Energy provided certain transition services to CTG and I Squared Capital. Cash flows related to providing the transition services were not material as of December 31, 2017. All transition services related to the International Disposal Group ended in 2017. Additionally, Duke Energy will reimburse CTG and I Squared Capital for all tax obligations arising from the period preceding consummation on the transactions, and recorded a liability of $54 million and $78 million as of December 31, 2018, and 2017, respectively. Duke Energy has not recorded any other liabilities, contingent liabilities or indemnifications related to the International Disposal Group.

 

3. BUSINESS SEGMENTS

Reportable segments are determined based on information used by the chief operating decision-maker in deciding how to allocate resources and evaluate the performance of the business. Duke Energy evaluates segment performance based on segment income. Segment income is defined as income from continuing operations net of income attributable to noncontrolling interests. Segment income, as discussed below, includes intercompany revenues and expenses that are eliminated on the Consolidated Financial Statements. Certain governance costs are allocated to each segment. In addition, direct interest expense and income taxes are included in segment income.

Products and services are sold between affiliate companies and reportable segments of Duke Energy at cost. Segment assets as presented in the tables that follow exclude all intercompany assets.

Duke Energy

Duke Energy's segment structure includes the following segments: Electric Utilities and Infrastructure, Gas Utilities and Infrastructure and Commercial Renewables.

The Electric Utilities and Infrastructure segment includes Duke Energy's regulated electric utilities in the Carolinas, Florida and the Midwest. The regulated electric utilities conduct operations through the Subsidiary Registrants that are substantially all regulated and, accordingly, qualify for regulatory accounting treatment. Electric Utilities and Infrastructure also includes Duke Energy's commercial electric transmission infrastructure investments.

The Gas Utilities and Infrastructure segment includes Piedmont, Duke Energy's natural gas local distribution companies in Ohio and Kentucky, and Duke Energy's natural gas storage and midstream pipeline investments. Gas Utilities and Infrastructure's operations are substantially all regulated and, accordingly, qualify for regulatory accounting treatment.

The Commercial Renewables segment is primarily comprised of nonregulated utility scale wind and solar generation assets located throughout the U.S.

The remainder of Duke Energy’s operations is presented as Other, which is primarily comprised of interest expense on holding company debt, unallocated corporate costs and Duke Energy’s wholly owned captive insurance company, Bison. Other also includes Duke Energy's interest in NMC. See Note 12 for additional information on the investment in NMC.

 

 

 

 

 

 

 

 

 

 

 

Business segment information is presented in the following tables. Segment assets presented exclude intercompany assets.

 

Year Ended December 31, 2018

 

Electric

 

Gas

 

 

 

Total

 

 

 

 

 

 

 

Utilities and

 

Utilities and

 

Commercial

 

Reportable

 

 

 

 

 

 

(in millions)

Infrastructure

 

Infrastructure

 

Renewables

 

Segments

 

Other

 

Eliminations

 

Total

Unaffiliated Revenues

$

22,242

 

 

$

1,783

 

 

$

477

 

 

$

24,502

 

 

$

19

 

 

$

 

 

$

24,521

 

Intersegment Revenues

31

 

 

98

 

 

 

 

129

 

 

70

 

 

(199

)

 

 

Total Revenues

$

22,273

 

 

$

1,881

 

 

$

477

 

 

$

24,631

 

 

$

89

 

 

$

(199

)

 

$

24,521

 

Interest Expense

$

1,288

 

 

$

106

 

 

$

88

 

 

$

1,482

 

 

$

657

 

 

$

(45

)

 

$

2,094

 

Depreciation and amortization

3,523

 

 

245

 

 

155

 

 

3,923

 

 

152

 

 

(1

)

 

4,074

 

Equity in earnings (losses) of unconsolidated affiliates

5

 

 

27

 

 

(1

)

 

31

 

 

52

 

 

 

 

83

 

Income tax expense (benefit)(a)

799

 

 

78

 

 

(147

)

 

730

 

 

(282

)

 

 

 

448

 

Segment income (loss)(b)(c)(d)(e)

3,058

 

 

274

 

 

9

 

 

3,341

 

 

(694

)

 

 

 

2,647

 

Add back noncontrolling interest component

 

 

 

 

 

 

 

 

 

 

 

 

(22

)

Income from discontinued operations, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

19

 

Net income

 

 

 

 

 

 

 

 

 

 

 

 

$

2,644

 

Capital investments expenditures and acquisitions

$

8,086

 

 

$

1,133

 

 

$

193

 

 

$

9,412

 

 

$

256

 

 

$

 

 

$

9,668

 

Segment assets

125,364

 

 

12,361

 

 

4,204

 

 

141,929

 

 

3,275

 

 

188

 

 

145,392

 

(a) All segments include adjustments to the December 31, 2017 estimate of the income tax effects of the Tax Act. Electric Utilities and Infrastructure includes a $24 million expense, Gas Utilities and Infrastructure includes a $1 million expense, Commercial Renewables includes a $3 million benefit and Other includes a $2 million benefit. See Note 23 for additional information.

(b) Electric Utilities and Infrastructure includes after-tax regulatory and legislative impairment charges of $202 million related to rate case orders, settlements or other actions of regulators or legislative bodies and an after-tax impairment charge of $46 million related to the Citrus County CC at Duke Energy Florida. See Note 4 for additional information.

(c) Gas Utilities and Infrastructure includes an after-tax impairment charge of $42 million for the investment in Constitution. See Note 12 for additional information.

(d) Commercial Renewables includes an impairment charge of $91 million, net of $2 million Noncontrolling interests, related to goodwill. See Note 11 for additional information.

(e) Other includes $65 million of after-tax costs to achieve the Piedmont merger, $144 million of after-tax severance charges related to a companywide initiative and an $82 million after-tax loss on the sale of the retired Beckjord Generating Station described below. For additional information, see Note 2 for the Piedmont Merger and Note 20 for severance charges.

 

 

 

In February 2018, Duke Energy sold Beckjord, a nonregulated facility retired during 2014, and recorded a pretax loss of $106 million within (Losses) Gains on Sales of Other Assets and Other, net and $1 million within Operation, maintenance and other on Duke Energy's Consolidated Statements of Operations for the year ended December 31, 2018. The sale included the transfer of coal ash basins and other real property and indemnification from any and all potential future claims related to the property, whether arising under environmental laws or otherwise.

 

Year Ended December 31, 2017

 

Electric

 

Gas

 

 

 

Total

 

 

 

 

 

 

 

Utilities and

 

Utilities and

 

Commercial

 

Reportable

 

 

 

 

 

 

(in millions)

Infrastructure

 

Infrastructure

 

Renewables

 

Segments

 

Other

 

Eliminations

 

Total

Unaffiliated Revenues

$

21,300

 

 

$

1,743

 

 

$

460

 

 

$

23,503

 

 

$

62

 

 

$

 

 

$

23,565

 

Intersegment Revenues

31

 

 

93

 

 

 

 

124

 

 

76

 

 

(200

)

 

 

Total Revenues

$

21,331

 

 

$

1,836

 

 

$

460

 

 

$

23,627

 

 

$

138

 

 

$

(200

)

 

$

23,565

Interest Expense

$

1,240

 

 

$

105

 

 

$

87

 

 

$

1,432

 

 

$

574

 

 

$

(20

)

 

$

1,986

 

Depreciation and amortization

3,010

 

 

231

 

 

155

 

 

3,396

 

 

131

 

 

 

 

3,527

 

Equity in earnings (losses) of unconsolidated affiliates

5

 

 

62

 

 

(5

)

 

62

 

 

57

 

 

 

 

119

 

Income tax expense (benefit)(a)

1,355

 

 

116

 

 

(628

)

 

843

 

 

353

 

 

 

 

1,196

 

Segment income (loss)(b)(c)(d)

3,210

 

 

319

 

 

441

 

 

3,970

 

 

(905

)

 

 

 

3,065

 

Add back noncontrolling interest component

 

 

 

 

 

 

 

 

 

 

 

 

5

 

Loss from discontinued operations, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

(6

)

Net income

 

 

 

 

 

 

 

 

 

 

 

 

$

3,064

 

Capital investments expenditures and acquisitions

$

7,024

 

 

$

907

 

 

$

92

 

 

$

8,023

 

 

$

175

 

 

$

 

 

$

8,198

 

Segment assets

119,423

 

 

11,462

 

 

4,156

 

 

135,041

 

 

2,685

 

 

188

 

 

137,914

 

(a) All segments include impacts of the Tax Act. Electric Utilities and Infrastructure includes a $231 million benefit, Gas Utilities and Infrastructure includes a $26 million benefit, Commercial Renewables includes a $442 million benefit and Other includes charges of $597 million.

(b) Electric Utilities and Infrastructure includes after-tax regulatory settlement charges of $98 million. See Note 4 for additional information.

(c) Commercial Renewables includes after-tax impairment charges of $74 million related to certain wind projects and the Energy Management Solutions reporting unit. See Notes 10 and 11 for additional information.

(d) Other includes $64 million of after-tax costs to achieve the Piedmont merger. See Note 2 for additional information.

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2016

 

Electric

 

Gas

 

 

 

Total

 

 

 

 

 

 

 

Utilities and

 

Utilities and

 

Commercial

 

Reportable

 

 

 

 

 

 

(in millions)

Infrastructure

 

Infrastructure

 

Renewables

 

Segments

 

Other

 

Eliminations

 

Total

Unaffiliated Revenues

$

21,336

 

 

$

875

 

 

$

484

 

 

$

22,695

 

 

$

48

 

 

$

 

 

$

22,743

 

Intersegment Revenues

30

 

 

26

 

 

 

 

56

 

 

69

 

 

(125

)

 

 

Total Revenues

$

21,366

 

 

$

901

 

 

$

484

 

 

$

22,751

 

 

$

117

 

 

$

(125

)

 

$

22,743

 

Interest Expense

$

1,136

 

 

$

46

 

 

$

53

 

 

$

1,235

 

 

$

693

 

 

$

(12

)

 

$

1,916

 

Depreciation and amortization

2,897

 

 

115

 

 

130

 

 

3,142

 

 

152

 

 

 

 

3,294

 

Equity in earnings (losses) of unconsolidated affiliates(a)

5

 

 

19

 

 

(82

)

 

(58

)

 

43

 

 

 

 

(15

)

Income tax expense (benefit)

1,672

 

 

90

 

 

(160

)

 

1,602

 

 

(446

)

 

 

 

1,156

 

Segment income (loss)(b)(c)

3,040

 

 

152

 

 

23

 

 

3,215

 

 

(645

)

 

1

 

 

2,571

 

Add back noncontrolling interest component

 

 

 

 

 

 

 

 

 

 

 

 

7

 

Loss from discontinued operations, net of tax(d)

 

 

 

 

 

 

 

 

 

 

 

 

(408

)

Net income

 

 

 

 

 

 

 

 

 

 

 

 

$

2,170

 

Capital investments expenditures and acquisitions(e)

$

6,649

 

 

$

5,519

 

 

$

857

 

 

$

13,025

 

 

$

190

 

 

$

 

 

$

13,215

 

Segment assets

114,993

 

 

10,760

 

 

4,377

 

 

130,130

 

 

2,443

 

 

188

 

 

132,761

 

 

(a) Commercial Renewables includes a pretax impairment charge of $71 million. See Note 12 for additional information.

(b) Other includes $329 million of after-tax costs to achieve mergers. See Note 2 for additional information on costs related to the Piedmont merger.

(c) Other includes after-tax charges of $57 million related to cost savings initiatives. See Note 20 for further information.

(d) Includes a loss on sale of the International Disposal Group. Refer to Note 2 for further information.

(e) Other includes $26 million of capital investment expenditures related to the International Disposal Group. Gas Utilities and Infrastructure includes the Piedmont acquisition of $5 billion. See Note 2 for more information on the Piedmont acquisition.

 

 

 

 

 

 

 

 

 

 

 

Geographical Information

All assets and revenues from continuing operations are within the U.S.

Major Customers

For the year ended December 31, 2018, revenues from one customer of Duke Energy Progress are $633 million. Duke Energy Progress has one reportable segment, Electric Utilities and Infrastructure. No other Subsidiary Registrant has an individual customer representing more than 10 percent of its revenues.

Products and Services

The following table summarizes revenues of the reportable segments by type.

 

Retail

 

Wholesale

 

Retail

 

 

 

Total

(in millions)

Electric

 

Electric

 

Natural Gas

 

Other

 

Revenues

2018

 

 

 

 

 

 

 

 

 

Electric Utilities and Infrastructure

$

19,013

 

 

$

2,345

 

 

$

 

 

$

915

 

 

$

22,273

 

Gas Utilities and Infrastructure

 

 

 

 

1,817

 

 

64

 

 

1,881

 

Commercial Renewables

 

 

375

 

 

 

 

102

 

 

477

 

Total Reportable Segments

$

19,013

 

 

$

2,720

 

 

$

1,817

 

 

$

1,081

 

 

$

24,631

 

2017

 

 

 

 

 

 

 

 

 

Electric Utilities and Infrastructure

$

18,177

 

 

$

2,104

 

 

$

 

 

$

1,050

 

 

$

21,331

 

Gas Utilities and Infrastructure

 

 

 

 

1,732

 

 

104

 

 

1,836

Commercial Renewables

 

 

375

 

 

 

 

85

 

 

460

 

Total Reportable Segments

$

18,177

 

 

$

2,479

 

 

$

1,732

 

 

$

1,239

 

 

$

23,627

 

2016

 

 

 

 

 

 

 

 

 

Electric Utilities and Infrastructure

$

18,338

 

 

$

2,095

 

 

$

 

 

$

933

 

 

$

21,366

 

Gas Utilities and Infrastructure

 

 

 

 

871

 

 

30

 

 

901

 

Commercial Renewables

 

 

303

 

 

 

 

181

 

 

484

 

Total Reportable Segments

$

18,338

 

 

$

2,398

 

 

$

871

 

 

$

1,144

 

 

$

22,751

 

Duke Energy Ohio

Duke Energy Ohio has two reportable segments, Electric Utilities and Infrastructure and Gas Utilities and Infrastructure.

Electric Utilities and Infrastructure transmits and distributes electricity in portions of Ohio and generates, distributes and sells electricity in portions of Northern Kentucky. Gas Utilities and Infrastructure transports and sells natural gas in portions of Ohio and Northern Kentucky. Both reportable segments conduct operations primarily through Duke Energy Ohio and its wholly owned subsidiary, Duke Energy Kentucky.

The remainder of Duke Energy Ohio's operations is presented as Other. In December 2018, the PUCO approved an order which allows the recovery or credit of revenues and expenses related to Duke Energy Ohio's contractual arrangement to buy power from OVEC power plants. Due to the change in regulatory treatment of these amounts, OVEC revenues and expenses are now reflected in the Electric Utilities and Infrastructure segment. Previously, OVEC revenues and expense were included in Other. These amounts are deemed immaterial for Duke Energy Ohio. Therefore, no prior period amounts were restated. See Note 4 for additional information on the PUCO order.

 

 

 

All Duke Energy Ohio assets and revenues from continuing operations are within the U.S.

 

Year Ended December 31, 2018

 

Electric

 

Gas

 

Total

 

 

 

 

 

Utilities and

 

Utilities and

 

Reportable

 

 

 

 

(in millions)

Infrastructure

 

Infrastructure

 

Segments

 

Other

 

Total

Total revenues

$

1,450

 

 

$

506

 

 

$

1,956

 

 

$

1

 

 

$

1,957

 

Interest expense

$

67

 

 

$

24

 

 

$

91

 

 

$

1

 

 

$

92

 

Depreciation and amortization

183

 

 

85

 

 

268

 

 

 

 

268

 

Income tax expense (benefit)

47

 

 

24

 

 

71

 

 

(28

)

 

43

 

Segment income (loss)/Net income(a)

186

 

 

93

 

 

279

 

 

(103

)

 

176

 

Capital expenditures

$

655

 

 

$

172

 

 

$

827

 

 

$

 

 

$

827

 

Segment assets

5,643

 

 

2,874

 

 

8,517

 

 

38

 

 

8,555

 

(a) Other includes the loss on the sale of Beckjord, see discussion above.

 

Year Ended December 31, 2017

 

Electric

 

Gas

 

Total

 

 

 

 

 

 

 

Utilities and

 

Utilities and

 

Reportable

 

 

 

 

 

 

(in millions)

Infrastructure

 

Infrastructure

 

Segments

 

Other

 

Eliminations

 

Total

Total revenues

$

1,373

 

 

$

508

 

 

$

1,881

 

 

$

42

 

 

$

 

 

$

1,923

 

Interest expense

$

62

 

 

$

28

 

 

$

90

 

 

$

1

 

 

$

 

 

$

91

 

Depreciation and amortization

178

 

 

83

 

 

261

 

 

 

 

 

 

261

 

Income tax expense (benefit)

40

 

 

39

 

 

79

 

 

(20

)

 

 

 

59

 

Segment income (loss)

138

 

 

85

 

 

223

 

 

(30

)

 

 

 

193

 

Loss from discontinued operations, net of tax

 

 

 

 

 

 

 

 

 

 

(1

)

Net income

 

 

 

 

 

 

 

 

 

 

$

192

 

Capital expenditures

$

491

 

 

$

195

 

 

$

686

 

 

$

 

 

$

 

 

$

686

 

Segment assets

5,066

 

 

2,758

 

 

7,824

 

 

66

 

 

(15

)

 

7,875

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2016

 

Electric

 

Gas

 

Total

 

 

 

 

 

 

 

Utilities and

 

Utilities and

 

Reportable

 

 

 

 

 

 

(in millions)

Infrastructure

 

Infrastructure

 

Segments

 

Other

 

Eliminations

 

Total

Total revenues

$

1,410

 

 

$

503

 

 

$

1,913

 

 

$

31

 

 

$

 

 

$

1,944

Interest expense

$

58

 

 

$

27

 

 

$

85

 

 

$

1

 

 

$

 

 

$

86

 

Depreciation and amortization

151

 

 

80

 

 

231

 

 

2

 

 

 

 

233

 

Income tax expense (benefit)

55

 

 

44

 

 

99

 

 

(21

)

 

 

 

78

 

Segment income (loss)

154

 

 

77

 

 

231

 

 

(39

)

 

 

 

192

 

Income from discontinued operations, net of tax

 

 

 

 

 

 

 

 

 

 

36

 

Net income

 

 

 

 

 

 

 

 

 

 

$

228

 

Capital expenditures

$

322

 

 

$

154

 

 

$

476

 

 

$

 

 

$

 

 

$

476

 

Segment assets

4,782

 

 

2,696

 

 

7,478

 

 

62

 

 

(12

)

 

7,528

 

4. REGULATORY MATTERS

REGULATORY ASSETS AND LIABILITIES

The Duke Energy Registrants record regulatory assets and liabilities that result from the ratemaking process. See Note 1 for further information.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The following tables present the regulatory assets and liabilities recorded on the Consolidated Balance Sheets of Duke Energy and Progress Energy. See separate tables below for balances by individual registrant.

 

Duke Energy

 

Progress Energy

 

December 31,

 

December 31,

(in millions)

2018

 

2017

 

2018

 

2017

Regulatory Assets

 

 

 

 

 

 

 

AROs – coal ash

$

4,255

 

 

$

4,025

 

 

$

2,061

 

 

$

1,984

 

AROs – nuclear and other

772

 

 

852

 

 

601

 

 

655

 

Accrued pension and OPEB

2,654

 

 

2,249

 

 

1,074

 

 

906

 

Retired generation facilities

445

 

 

480

 

 

367

 

 

386

 

Debt fair value adjustment

1,099

 

 

1,197

 

 

 

 

 

Deferred asset – Lee COLA

383

 

 

 

 

 

 

 

Storm cost deferrals

1,117

 

 

531

 

 

953

 

 

526

 

Nuclear asset securitized balance, net

1,093

 

 

1,142

 

 

1,093

 

 

1,142

 

Hedge costs deferrals

204

 

 

234

 

 

74

 

 

94

 

Derivatives – natural gas supply contracts

141

 

 

142

 

 

 

 

 

Demand side management (DSM)/Energy efficiency (EE)

449

 

 

530

 

 

256

 

 

281

 

Grid modernization

31

 

 

39

 

 

 

 

 

Vacation accrual

213

 

 

213

 

 

41

 

 

42

 

Deferred fuel and purchased power

838

 

 

507

 

 

600

 

 

349

 

Nuclear deferral

133

 

 

119

 

 

46

 

 

35

 

Post-in-service carrying costs (PISCC) and deferred operating expenses

320

 

 

366

 

 

36

 

 

38

 

Transmission expansion obligation

39

 

 

46

 

 

 

 

 

Manufactured gas plant (MGP)

99

 

 

91

 

 

 

 

 

Advanced metering infrastructure (AMI)

367

 

 

362

 

 

127

 

 

150

 

NCEMPA deferrals

50

 

 

53

 

 

50

 

 

53

 

East Bend deferrals

47

 

 

45

 

 

 

 

 

Deferred pipeline integrity costs

65

 

 

54

 

 

 

 

 

Amounts due from customers

24

 

 

64

 

 

 

 

 

Other

784

 

 

538

 

 

322

 

 

110

 

Total regulatory assets

15,622

 

 

13,879

 

 

7,701

 

 

6,751

 

Less: current portion

2,005

 

 

1,437

 

 

1,137

 

 

741

Total noncurrent regulatory assets

$

13,617

 

 

$

12,442

 

 

$

6,564

 

 

$

6,010

 

Regulatory Liabilities

 

 

 

 

 

 

 

Costs of removal

$

5,421

 

 

$

5,968

 

 

$

2,135

 

 

$

2,537

 

AROs – nuclear and other

538

 

 

806

 

 

 

 

 

Net regulatory liability related to income taxes

8,058

 

 

8,113

 

 

2,710

 

 

2,802

 

Amounts to be refunded to customers

34

 

 

10

 

 

 

 

 

Storm reserve

 

 

20

 

 

 

 

 

Accrued pension and OPEB

301

 

 

146

 

 

149

 

 

 

Deferred fuel and purchased power

16

 

 

47

 

 

16

 

 

1

 

Other

1,064

 

 

622

 

 

319

 

 

179

 

Total regulatory liabilities

15,432

 

 

15,732

 

 

5,329

 

 

5,519

 

Less: current portion

598

 

 

402

 

 

280

 

 

213

 

Total noncurrent regulatory liabilities

$

14,834

 

 

$

15,330

 

 

$

5,049

 

 

$

5,306

 

Descriptions of regulatory assets and liabilities summarized in the tables above and below follow. See tables below for recovery and amortization periods at the separate registrants.

AROs coal ash. Represents deferred depreciation and accretion related to the legal obligation to close ash basins. The costs are deferred until recovery treatment has been determined. See Notes 1 and 9 for additional information.

AROs nuclear and other. Represents regulatory assets or liabilities, including deferred depreciation and accretion, related to legal obligations associated with the future retirement of property, plant and equipment, excluding amounts related to coal ash. The AROs relate primarily to decommissioning nuclear power facilities. The amounts also include certain deferred gains and losses on NDTF investments. See Notes 1 and 9 for additional information.

Accrued pension and OPEB. Accrued pension and OPEB represent regulatory assets and liabilities related to each of the Duke Energy Registrants’ respective shares of unrecognized actuarial gains and losses and unrecognized prior service cost and credit attributable to Duke Energy’s pension plans and OPEB plans. The regulatory asset or liability is amortized with the recognition of actuarial gains and losses and prior service cost and credit to net periodic benefit costs for pension and OPEB plans. The accrued pension and OPEB regulatory asset is expected to be recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

Retired generation facilities. Represents amounts to be recovered for facilities that have been retired and are probable of recovery.

Debt fair value adjustment. Purchase accounting adjustments recorded to state the carrying value of Progress Energy and Piedmont at fair value in connection with the 2012 and 2016 mergers, respectively. Amount is amortized over the life of the related debt.

Net regulatory asset or liability related to income taxes. Amounts for all registrants include regulatory liabilities related primarily to impacts from the Tax Act. See Note 23 for additional information. Amounts have no immediate impact on rate base as regulatory assets are offset by deferred tax liabilities.

Deferred asset – Lee COLA. Represents deferred costs incurred for the canceled Lee nuclear project.

Storm cost deferrals. Represents deferred incremental costs incurred related to extraordinary weather-related events.

Nuclear asset securitized balance, net. Represents the balance associated with Crystal River Unit 3 retirement approved for recovery by the FPSC on September 15, 2015, and the upfront financing costs securitized in 2016 with issuance of the associated bonds. The regulatory asset balance is net of the AFUDC equity portion.

Hedge costs and other deferrals. Amounts relate to unrealized gains and losses on derivatives recorded as a regulatory asset or liability, respectively, until the contracts are settled.

Derivatives – natural gas supply contracts. Represents costs for certain long-dated, fixed quantity forward gas supply contracts, which are recoverable through PGA clauses.

DSM/EE. Deferred costs related to various DSM and EE programs recoverable through various mechanisms.

Grid modernization. Amounts represent deferred depreciation and operating expenses as well as carrying costs on the portion of capital expenditures placed in service but not yet reflected in retail rates as plant in service.

Vacation accrual. Represents.vacation entitlement, which is generally recovered in the following year.

Deferred fuel and purchased power. Represents certain energy-related costs that are recoverable or refundable as approved by the applicable regulatory body.

Nuclear deferral. Includes amounts related to levelizing nuclear plant outage costs, which allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, resulting in the deferral of operations and maintenance costs associated with refueling.

Post-in-service carrying costs and deferred operating expenses. Represents deferred depreciation and operating expenses as well as carrying costs on the portion of capital expenditures placed in service but not yet reflected in retail rates as plant in service.

Transmission expansion obligation. Represents transmission expansion obligations related to Duke Energy Ohio’s withdrawal from Midcontinent Independent System Operator, Inc. (MISO).

MGP. Represents remediation costs incurred at former MGP sites and the deferral of costs to be incurred at Duke Energy Ohio's East End and West End sites.

AMI. Represents deferred costs related to the installation of AMI meters and remaining net book value of non-AMI meters to be replaced at Duke Energy Carolinas, net book value of existing meters at Duke Energy Florida, Duke Energy Progress and Duke Energy Ohio and expected future recovery of net book value of electromechanical meters that have been replaced with AMI meters at Duke Energy Indiana.

NCEMPA deferrals. Represents retail allocated cost deferrals and returns associated with the additional ownership interest in assets acquired from NCEMPA in 2015.

East Bend deferrals. Represents both deferred operating expenses and deferred depreciation as well as carrying costs on the portion of East Bend that was acquired from Dayton Power and Light and that had been previously operated as a jointly owned facility.

Deferred pipeline integrity costs. Represents pipeline integrity management costs in compliance with federal regulations recovered through a rider mechanism.

Amounts due from customers. Relates primarily to margin decoupling and IMR recovery mechanisms.

Costs of removal. Represents funds received from customers to cover the future removal of property, plant and equipment from retired or abandoned sites as property is retired. Also includes certain deferred gains on NDTF investments.

Amounts to be refunded to customers. Represents required rate reductions to retail customers by the applicable regulatory body.

Storm reserve. Amounts are used to offset future incurred costs for named storms as approved by regulatory commissions.

RESTRICTIONS ON THE ABILITY OF CERTAIN SUBSIDIARIES TO MAKE DIVIDENDS, ADVANCES AND LOANS TO DUKE ENERGY

As a condition to the approval of merger transactions, the NCUC, PSCSC, PUCO, KPSC and IURC imposed conditions on the ability of Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio, Duke Energy Kentucky, Duke Energy Indiana and Piedmont to transfer funds to Duke Energy through loans or advances, as well as restricted amounts available to pay dividends to Duke Energy. Certain subsidiaries may transfer funds to the parent by obtaining approval of the respective state regulatory commissions. These conditions imposed restrictions on the ability of the public utility subsidiaries to pay cash dividends as discussed below.

Duke Energy Progress and Duke Energy Florida also have restrictions imposed by their first mortgage bond indentures, which in certain circumstances, limit their ability to make cash dividends or distributions on common stock. Amounts restricted as a result of these provisions were not material at December 31, 2018.

Additionally, certain other subsidiaries of Duke Energy have restrictions on their ability to dividend, loan or advance funds to Duke Energy due to specific legal or regulatory restrictions, including, but not limited to, minimum working capital and tangible net worth requirements.

The restrictions discussed below were not a material amount of Duke Energy's and Progress Energy's net assets at December 31, 2018.

Duke Energy Carolinas

Duke Energy Carolinas must limit cumulative distributions subsequent to mergers to (i) the amount of retained earnings on the day prior to the closing of the mergers, plus (ii) any future earnings recorded.

Duke Energy Progress

Duke Energy Progress must limit cumulative distributions subsequent to the mergers between Duke Energy and Progress Energy and Duke Energy and Piedmont to (i) the amount of retained earnings on the day prior to the closing of the respective mergers, plus (ii) any future earnings recorded.

Duke Energy Ohio

Duke Energy Ohio will not declare and pay dividends out of capital or unearned surplus without the prior authorization of the PUCO. Duke Energy Ohio received FERC and PUCO approval to pay dividends from its equity accounts that are reflective of the amount that it would have in its retained earnings account had push-down accounting for the Cinergy merger not been applied to Duke Energy Ohio’s balance sheet. The conditions include a commitment from Duke Energy Ohio that equity, adjusted to remove the impacts of push-down accounting, will not fall below 30 percent of total capital.

Duke Energy Kentucky is required to pay dividends solely out of retained earnings and to maintain a minimum of 35 percent equity in its capital structure.

Duke Energy Indiana

Duke Energy Indiana must limit cumulative distributions subsequent to the merger between Duke Energy and Cinergy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded. In addition, Duke Energy Indiana will not declare and pay dividends out of capital or unearned surplus without prior authorization of the IURC.

Piedmont

Piedmont must limit cumulative distributions subsequent to the acquisition of Piedmont by Duke Energy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded.

RATE-RELATED INFORMATION

The NCUC, PSCSC, FPSC, IURC, PUCO, TPUC and KPSC approve rates for retail electric and natural gas services within their states. The FERC approves rates for electric sales to wholesale customers served under cost-based rates (excluding Ohio and Indiana), as well as sales of transmission service. The FERC also regulates certification and siting of new interstate natural gas pipeline projects.

Duke Energy Carolinas and Duke Energy Progress

Grid Improvement – South Carolina

On June 22, 2018, Duke Energy Carolinas and Duke Energy Progress filed a joint petition with the PSCSC seeking an accounting order authorizing deferral of certain costs incurred in connection with grid reliability, resiliency and modernization work that is being performed under the companies’ grid improvement initiative. On October 3, 2018, the PSCSC granted Duke Energy Carolinas' and Duke Energy Progress' joint petition, which authorizes the deferral of these costs until the rate effective dates of each Company’s next general rate case.

Hurricane Florence, Hurricane Michael and Winter Storm Diego

In September 2018, Hurricane Florence made landfall and inflicted severe damage to the Duke Energy Carolinas and Duke Energy Progress territories in North Carolina and South Carolina. Approximately 2 million customers were impacted. The companies incurred approximately $500 million in incremental operation and maintenance expenses ($70 million and $430 million for Duke Energy Carolinas and Duke Energy Progress, respectively,) and approximately $90 million in capital costs ($5 million and $85 million for Duke Energy Carolinas and Duke Energy Progress, respectively,) which are included in Net property, plant and equipment on the Consolidated Balance Sheets as of December 31, 2018, resulting from the hurricane restoration efforts. Most of the operation and maintenance expenses are deferred in Regulatory assets within Other Noncurrent Assets on the Consolidated Balance Sheets as of December 31, 2018. The balance of operation and maintenance expenses are included in Operation, maintenance and other on the Consolidated Statements of Operations for the year ended December 31, 2018.

In October 2018, the remnants of Hurricane Michael inflicted severe damage to the Duke Energy Carolinas and Duke Energy Progress territories in North Carolina and South Carolina. Approximately 1 million customers were impacted. The companies incurred approximately $100 million in incremental operation and maintenance expenses ($75 million and $25 million for Duke Energy Carolinas and Duke Energy Progress, respectively,) and approximately $21 million in capital costs ($12 million and $9 million for Duke Energy Carolinas and Duke Energy Progress, respectively,) which are included in Net property, plant and equipment on the Consolidated Balance Sheets as of December 31, 2018, resulting from the hurricane restoration efforts. Most of the operation and maintenance expenses are deferred in Regulatory assets within Other Noncurrent Assets on the Consolidated Balance Sheets as of December 31, 2018. The balance of operation and maintenance expenses are included in Operation, maintenance and other on the Consolidated Statements of Operations for the year ended December 31, 2018.

In December 2018, Winter Storm Diego inflicted severe damage to the Duke Energy Carolinas and Duke Energy Progress territories in North Carolina and South Carolina. Approximately 800,000 customers were impacted. The companies incurred approximately $85 million in incremental operation and maintenance expenses ($60 million and $25 million for Duke Energy Carolinas and Duke Energy Progress, respectively,) and approximately $9 million in capital costs ($7 million and $2 million for Duke Energy Carolinas and Duke Energy Progress, respectively,) which are included in Net property, plant and equipment on the Consolidated Balance Sheets as of December 31, 2018, resulting from the winter storm restoration efforts. Most of the operation and maintenance expenses are deferred in Regulatory assets within Other Noncurrent Assets on the Consolidated Balance Sheets as of December 31, 2018. The balance of operation and maintenance expenses are included in Operation, maintenance and other on the Consolidated Statements of Operations for the year ended December 31, 2018.

On December 21, 2018, Duke Energy Carolinas and Duke Energy Progress filed with the NCUC petitions for approval to defer the incremental costs incurred to a regulatory asset for recovery in the next base rate case. The NCUC issued an order requesting comments on the deferral positions. Duke Energy Carolinas and Duke Energy Progress cannot predict the outcome of this matter. Duke Energy Progress filed a similar request with the PSCSC on January 11, 2019, which also included a request for the continuation of prior deferrals requested for ice storms and Hurricane Matthew, and on January 30, 2019, the PSCSC issued a directive approving the deferral request.

North Carolina State Corporate Income Tax

On December 12, 2018, Duke Energy Carolinas and Duke Energy Progress filed requests to reduce their rates effective January 1, 2019, based on a reduction in North Carolina’s corporate income tax rate from 3 to 2.5 percent, as enacted by the General Assembly in Session Law 2017-57, which became law on June 28, 2017, with an effective date of January 1, 2019. On December 17, 2018, the NCUC issued orders approving the Duke Energy Carolinas and Duke Energy Progress rate decrements.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Duke Energy Carolinas

Regulatory Assets and Liabilities

The following tables present the regulatory assets and liabilities recorded on Duke Energy Carolinas' Consolidated Balance Sheets.

 

December 31,

 

Earns/Pays

Recovery/Refund

(in millions)

2018

2017

 

a Return

Period Ends

Regulatory Assets(a)

 

 

 

 

 

AROs – coal ash

$

1,725

 

$

1,645

 

 

(i)

(b)

Accrued pension and OPEB

581

 

410

 

 

 

(j)

Retired generation facilities(c)

21

 

29

 

 

X

2023

Deferred Asset – Lee COLA

383

 

 

 

 

(b)

Storm cost deferrals

160

 

 

 

X

(b)

Hedge costs deferrals(c)

101

 

109

 

 

X

2041

DSM/EE

169

 

210

 

 

(h)

(h)

Vacation accrual

78

 

83

 

 

(e)

2019

Deferred fuel and purchased power

196

 

140

 

 

(f)

2020

Nuclear deferral

87

 

84

 

 

 

2020

PISCC(c)

34

 

35

 

 

X

(b)

AMI

176

 

185

 

 

X

(b)

Other

266

 

222

 

 

 

(b)

Total regulatory assets

3,977

 

3,152

 

 

 

 

Less: current portion

520

 

299

 

 

 

 

Total noncurrent regulatory assets

$

3,457

 

$

2,853

 

 

 

 

Regulatory Liabilities(a)

 

 

 

 

 

Costs of removal(c)

$

1,968

 

$

2,054

 

 

X

(g)

ARO – nuclear and other

538

 

806

 

 

 

(b)

Net regulatory liability related to income taxes(d)

3,082

 

3,028

 

 

 

(b)

Storm reserve(c)

 

20

 

 

 

(b)

Accrued pension and OPEB

38

 

44

 

 

 

(j)

Deferred fuel and purchased power

 

46

 

 

(f)

2020

Other

572

 

359

 

 

 

(b)

Total regulatory liabilities

6,198

 

6,357

 

 

 

 

Less: current portion

199

 

126

 

 

 

 

Total noncurrent regulatory liabilities

$

5,999

 

$

6,231

 

 

 

 

(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) The expected recovery or refund period varies or has not been determined.

(c) Included in rate base.

(d) Includes regulatory liabilities related to the change in the federal tax rate as a result of the Tax Act and the change in the North Carolina tax rate, both discussed in Note 23.

(e) Earns a return on outstanding balance in North Carolina.

(f) Pays interest on over-recovered costs in North Carolina. Includes certain purchased power costs in North Carolina and South Carolina and costs of distributed energy in South Carolina.

(g) Recovered over the life of the associated assets.

(h) Includes incentives on DSM/EE investments and is recovered through an annual rider mechanism.

(i) Earns a debt and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders.

(j) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

2017 North Carolina Rate Case

On August 25, 2017, Duke Energy Carolinas filed an application with the NCUC for a rate increase for retail customers of approximately $647 million, which represented an approximate 13.6 percent increase in annual base revenues. The rate increase was driven by capital investments subsequent to the previous base rate case, including the W.S. Lee CC discussed below, grid improvement projects, AMI, investments in customer service technologies, costs of complying with CCR regulations and the Coal Ash Act and recovery of costs related to licensing and development of the Lee Nuclear Station discussed below.

On February 28, 2018, Duke Energy Carolinas and the North Carolina Public Staff (Public Staff) filed an Agreement and Stipulation of Partial Settlement resolving certain portions of the proceeding. Terms of the settlement included a return on equity of 9.9 percent and a capital structure of 52 percent equity and 48 percent debt. As a result of the settlement, Duke Energy Carolinas recorded a pretax charge of approximately $4 million to Operation, maintenance and other on the Consolidated Statements of Operations.

On June 1, 2018, Duke Energy Carolinas and certain intervenors filed a Pilot Grid Rider Agreement and Stipulation (Grid Rider Stipulation) in which the parties agreed to the proposal Duke Energy Carolinas introduced in a post-hearing brief on April 27, 2018, along with additional commitments by Duke Energy Carolinas. Also on June 1, 2018, Duke Energy Carolinas and the Commercial Group filed a Partial Stipulation and Settlement Agreement to be considered in conjunction with the Stipulation.

Components of the Grid Rider Stipulation included:

  • Duke Energy Carolinas would recover grid improvement costs through a pilot, three-year Grid Rider except for costs related to targeted undergrounding of power lines, cable and conduit replacement, and power pole replacement;

  • Excluded costs were to be deferred with a return until Duke Energy Carolinas’ next base rate case proceeding; and

  • Costs incurred during the three-year pilot, both rider recoverable and deferred, were subject to a 4.5 percent cumulative cap of total annual electric service revenue.

On June 22, 2018, the NCUC issued an order approving the Stipulation of Partial Settlement and requiring a revenue reduction. The order also included the following material components not covered in the Stipulation:

  • Recovery of $554 million of deferred coal ash basin closure costs over a five-year period with a return at Duke Energy Carolinas' WACC;

  • Assessment of a $70 million management penalty ratably over a five-year period by reducing the annual recovery of the deferred coal ash costs;

  • Denial of Duke Energy Carolinas' request for recovery of future estimated ongoing annual coal ash costs of $201 million with approval to defer such costs with a return at Duke Energy Carolinas' WACC, to be considered for recovery in the next rate case;

  • Inclusion in rates of costs related to the W.S. Lee CC, two new solar facilities, and AMI deployment as requested;

  • Recovery of Lee Nuclear Station licensing and development cost of $347 million over a 12-year period, but denial of a return on the deferred balance of costs;

  • Reduction in revenue related to lower income tax expense resulting from the Tax Act, and a requirement to maintain all excess deferred income tax (EDIT) resulting from the Tax Act in a regulatory liability account pending flow back to customers as approved by the commission at the earlier of three years or Duke Energy Carolinas’ next general rate case proceeding; and

  • Denial of the proposed Grid Rider Stipulation related to grid improvement costs and denial of deferral accounting treatment of the costs at this time. Duke Energy Carolinas may petition for deferral of grid modernization costs outside of a general rate case proceeding if it can show financial hardship or a stipulation that includes greater consensus among intervening parties on costs being classified as grid modernization.

As a result of the Order, Duke Energy Carolinas recorded a pretax charge of approximately $150 million to Impairment charges and Operation, maintenance and other on the Consolidated Statements of Operations. The charge is primarily related to the denial of a return on the Lee Nuclear Project and for previously recognized return impacted by the coal ash management penalty described above. On July 27, 2018, NCUC approved Duke Energy Carolinas' compliance filing. As a result, revised customer rates were effective on August 1, 2018.

On July 20, 2018, the North Carolina Attorney General filed a Notice of Appeal to the North Carolina Supreme Court from the June 22, 2018, Order Accepting Stipulation, Deciding Contested Issues and Requiring Revenue Reduction issued by the NCUC. The Attorney General contends the commission’s order should be reversed and remanded, as it is in excess of the commission’s statutory authority; affected by errors of law; unsupported by competent, material and substantial evidence in view of the entire record as submitted; and arbitrary or capricious. The Sierra Club, North Carolina Sustainable Energy Association, North Carolina Justice Center, North Carolina Housing Coalition, Natural Resource Defense Council and Southern Alliance for Clean Energy have also filed Notices of Appeal to the North Carolina Supreme Court from the June 22, 2018, Order Accepting Stipulation, Deciding Contested Issues and Requiring Revenue Reduction. On August 8, 2018, the Public Staff filed a Notice of Cross Appeal to the North Carolina Supreme Court from the June 22, 2018, Order Accepting Stipulation, Deciding Contested Issues and Requiring Revenue Reduction issued by the NCUC. The Public Staff contends the commission’s order should be reversed and remanded, as it is affected by errors of law, and is unsupported by substantial evidence with regard to the commission’s failure to consider substantial evidence of coal ash related environmental violations. On November 29, 2018, the North Carolina Attorney General's Office filed a motion with the North Carolina Supreme Court requesting the court consolidate the Duke Energy Carolinas and Duke Energy Progress appeals and enter an order adopting the parties’ proposed briefing schedule as set out in the filing. On November 29, 2018, the North Carolina Supreme Court adopted a schedule for briefing set forth in the motion to consolidate the Duke Energy Carolinas and Duke Energy Progress appeals. The Appellee response briefs are due July 29, 2019. Duke Energy Carolinas cannot predict the outcome of this matter.

2018 South Carolina Rate Case

On November 8, 2018, Duke Energy Carolinas filed an application with the PSCSC for a rate increase for retail customers of approximately $168 million, which represents an approximate 10.0 percent increase in retail revenues. The rate increase is driven by capital investments and environmental compliance progress made by Duke Energy Carolinas since its previous rate case, including the further implementation of Duke Energy Carolinas’ generation modernization program, which consists of retiring, replacing and upgrading generation plants, investments in customer service technologies and continued investments in base work to maintain its transmission and distribution systems. The request includes net tax benefits resulting from the Tax Act of $66 million to reflect the change in ongoing tax expense, primarily from the reduction in the federal income tax rate from 35 to 21 percent, and $46 million to return EDIT resulting from the federal tax rate change and deferred revenues since January 2018 related to the change and benefits of $17 million from a reduction in North Carolina state income taxes allocable to South Carolina.

Duke Energy Carolinas also requested approval of its proposed Grid Improvement Plan, adjustments to its Prepaid Advantage Program and a variety of accounting orders related to ongoing costs for environmental compliance, including recovery over a five-year period of $242 million of deferred coal ash related compliance costs, grid investments between rate changes, incremental depreciation expense, a result of new depreciation rates from the depreciation study approved in the 2017 North Carolina Rate Case above, and the balance of development costs associated with the cancellation of the Lee Nuclear Project. Finally, Duke Energy Carolinas sought approval to establish a reserve and accrual for end of life nuclear costs for nuclear fuel and materials and supplies. An evidentiary hearing is scheduled to begin on March 21, 2019, and a decision and revised customer rates are expected by mid-2019. Duke Energy Carolinas cannot predict the outcome of this matter.

FERC Formula Rate Matter

On July 31, 2017, PMPA filed a complaint with FERC alleging that Duke Energy Carolinas misapplied the formula rate under the PPA between the parties by including in its rates amortization expense associated with regulatory assets and recorded in a certain account without FERC approval. On February 15, 2018, FERC issued an order ruling in favor of PMPA and ordered Duke Energy Carolinas to refund to PMPA all amounts improperly collected under the PPA. Duke Energy Carolinas has issued to PMPA and similarly situated wholesale customers refunds of approximately $25 million. FERC also set the matter for settlement and hearing. PMPA and other customers filed a protest to Duke Energy Carolinas' refund report claiming that the refunds are inadequate in that (1) Duke Energy Carolinas invoked the limitations periods in the contracts to limit the time period for which the refunds were paid and the customers disagree that this limitation applies, and (2) Duke Energy Carolinas refunded only amounts recovered through a certain account and the customers have asserted that the order applies to all regulatory assets. On July 3, 2018, FERC issued an order accepting Duke Energy Carolinas' refund report and ruling that these two claims are outside the scope of FERC's February order. The settlement agreements and revised formula rates for all parties to the proceeding were filed on December 28, 2018. Duke Energy Carolinas cannot predict the outcome of this matter.

W.S. Lee CC

On April 9, 2014, the PSCSC granted Duke Energy Carolinas and NCEMC a CECPCN for the construction and operation of a 750-megawatt (MW) combined-cycle natural gas-fired generating plant at Duke Energy Carolinas' existing William States Lee Generating Station in Anderson, South Carolina. Duke Energy Carolinas began construction in July 2015 and its share of the cost to build the facility was approximately $650 million, including AFUDC. Approximately $600 million is being recovered through base rate or deferral filings in North Carolina and South Carolina. The remaining amount will be included in future rate filings. The project commenced commercial operation on April 5, 2018. NCEMC owns approximately 13 percent of the project.

Lee Nuclear Station

In December 2007, Duke Energy Carolinas applied to the NRC for COLs for two Westinghouse AP1000 reactors for the proposed William States Lee III Nuclear Station to be located at a site in Cherokee County, South Carolina. The NCUC and PSCSC concurred with the prudency of Duke Energy Carolinas incurring certain project development and preconstruction costs through several separately issued orders, although full cost recovery is not guaranteed. In December 2016, the NRC issued a COL for each reactor. Duke Energy Carolinas is not required to build the nuclear reactors as a result of the COLs being issued.

The Duke Energy Carolinas 2017 North Carolina Rate Case filing discussed above included a request to cancel the development of the Lee Nuclear project, recover incurred licensing and development costs and maintain the license issued by the NRC as an option for potential future development. The cancellation request was due to the Westinghouse bankruptcy filing and other market activity. The NCUC Order issued on June 22, 2018, approved the cancellation of the Lee Nuclear Project, allowed Duke Energy Carolinas to continue to maintain the COLs, provided for recovery of the North Carolina retail allocation of project development costs, including AFUDC accrued through December 31, 2017, over 12 years and disallowed any return on the unamortized balance during the 12-year recovery period.

Given the repeal of certain sections of the Base Load Review Act in South Carolina combined with the cancellation of the project, Duke Energy Carolinas determined that it was no longer probable it would be allowed a return on its share of project development costs attributable to South Carolina. As a result, Duke Energy Carolinas recorded a pretax impairment in the second quarter of 2018 of $29 million within Impairment charges on the Consolidated Statements of Operations and Comprehensive Income.

South Carolina Petition

On June 22, 2018, Duke Energy Carolinas filed a petition with the PSCSC requesting an accounting order to defer certain costs incurred in connection with the addition of the W.S. Lee CC, the ongoing deployment of Duke Energy Carolinas new billing and Customer Information System and the addition of the Carolinas West Primary Distribution Control Center. This request totaling approximately $33 million was approved on July 25, 2018.

Sale of Hydroelectric (Hydro) Plants

In May 2018, Duke Energy Carolinas entered an agreement for the sale of five hydro plants with a combined 18.7-MW generation capacity in the Western Carolinas region to Northbrook Energy. The completion of the transaction is subject to approval from FERC for the four FERC-licensed plants, as well as other state regulatory agencies and is contingent upon regulatory approval from the NCUC and PSCSC to defer the total estimated loss on the sale of approximately $40 million. On July 5, 2018, Duke Energy Carolinas filed with NCUC for approval of the sale of the five hydro plants to Northbrook, to transfer the CPCNs for the four North Carolina hydro plants and to establish a regulatory asset for the North Carolina retail portion of the difference between sales proceeds and net book value. On September 4, 2018, the Public Staff filed comments supporting the CPCN transfer with conditions. On September 18, 2018, Duke Energy Carolinas filed reply comments opposing the Public Staff’s proposed conditions. On November 29, 2018, the NCUC issued a procedural order and held an evidentiary hearing on this matter on February 5, 2019. On August 28, 2018, Duke Energy Carolinas filed with PSCSC its Application for Approval of Transfer and Sale of Hydroelectric Generation Facilities, Acceptance for Filing of a Power Purchase Agreement and an Accounting Order to Establish a Regulatory Asset. On September 10, 2018, the ORS provided a letter to the commission stating its position on the application and on September 18, 2018, Duke Energy Carolinas requested this matter be carried over to allow Duke Energy Carolinas time to discuss certain accounting issues with the ORS. On August 9, 2018, Duke Energy Carolinas and Northbrook filed a joint Application for Transfer of Licenses with the FERC. On December 27, 2018, the FERC issued its Order Approving Transfer of Licenses (“Order”) for the four FERC-licensed hydro plants. On January 18, 2019, Duke Energy Carolinas and Northbrook Carolina Hydro II, LLC requested a six-month extension of time to comply with the requirement of the Order that Northbrook submit to FERC certified copies of all instruments of conveyance and signed acceptance sheets within 60 days of the date of the Order, given that compliance by the deadline set in the Order is not possible because the conveyance of the projects is contingent on the receipt of state regulatory approvals, which are not anticipated to be issued by February 25, 2019.

If commission approvals are not received, Duke Energy Carolinas can cancel the sales agreement and retain the hydro facilities. If commission approvals are received, the closing is expected to occur during the second quarter of 2019. After closing, Duke Energy Carolinas will purchase all the capacity and energy generated by these facilities at the avoided cost for five years through power purchase agreements. Duke Energy Carolinas cannot predict the outcome of this matter.

Duke Energy Progress

Regulatory Assets and Liabilities

The following tables present the regulatory assets and liabilities recorded on Duke Energy Progress' Consolidated Balance Sheets.

 

December 31,

 

Earns/Pays

Recovery/Refund

(in millions)

2018

2017

 

a Return

Period Ends

Regulatory Assets(a)

 

 

 

 

 

AROs – coal ash

$

2,051

 

$

1,975

 

 

(h)

(b)

AROs – nuclear and other

429

 

359

 

 

 

(c)

Accrued pension and OPEB

542

 

430

 

 

 

(k)

Retired generation facilities

148

 

170

 

 

X

(b)

Storm cost deferrals(d)

571

 

150

 

 

X

(b)

Hedge costs deferrals

54

 

64

 

 

 

(b)

DSM/EE(e)

235

 

264

 

 

(i)

(i)

Vacation accrual

41

 

42

 

 

 

2019

Deferred fuel and purchased power

397

 

130

 

 

(f)

2020

Nuclear deferral

46

 

35

 

 

 

2020

PISCC and deferred operating expenses

36

 

38

 

 

X

2054

AMI

67

 

75

 

 

 

(b)

NCEMPA deferrals

50

 

53

 

 

(g)

2042

Other

147

 

74

 

 

 

(b)

Total regulatory assets

4,814

 

3,859

 

 

 

 

Less: current portion

703

 

352

 

 

 

 

Total noncurrent regulatory assets

$

4,111

 

$

3,507

 

 

 

 

Regulatory Liabilities(a)

 

 

 

 

 

Costs of removal

$

1,878

 

$

2,122

 

 

X

(j)

Accrued pension and OPEB

93

 

 

 

 

(k)

Net regulatory liability related to income taxes(l)

1,863

 

1,854

 

 

 

(b)

Deferred fuel and purchased power

 

1

 

 

(f)

2020

Other

299

 

161

 

 

 

(b)

Total regulatory liabilities

4,133

 

4,138

 

 

 

 

Less: current portion

178

 

139

 

 

 

 

Total noncurrent regulatory liabilities

$

3,955

 

$

3,999

 

 

 

 

 

(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) The expected recovery or refund period varies or has not been determined.

(c) Recovery period for costs related to nuclear facilities runs through the decommissioning period of each unit.

(d) South Carolina storm costs are included in rate base.

(e) Included in rate base.

(f) Pays interest on over-recovered costs in North Carolina. Includes certain purchased power costs in North Carolina and South Carolina and costs of distributed energy in South Carolina.

(g) South Carolina retail allocated costs are earning a return.

(h) Earns a debt and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders.

(i) Includes incentives on DSM/EE investments and is recovered through an annual rider mechanism.

(j) Recovered over the life of the associated assets.

(k) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

(l) Includes regulatory liabilities related to the change in the federal tax rate as a result of the Tax Act and the change in the North Carolina tax rate, both discussed in Note 23.

2017 North Carolina Rate Case

On June 1, 2017, Duke Energy Progress filed an application with the NCUC for a rate increase for retail customers of approximately $477 million, which represented an approximate 14.9 percent increase in annual base revenues. Subsequent to the filing, Duke Energy Progress adjusted the requested amount to $420 million, representing an approximate 13 percent increase. The rate increase is driven by capital investments subsequent to the previous base rate case, costs of complying with CCR regulations and the Coal Ash Act, costs relating to storm recovery, investments in customer service technologies and recovery of costs associated with renewable purchased power.

On December 16, 2016, Duke Energy Progress filed a petition with the NCUC requesting an accounting order to defer certain costs incurred in connection with response to Hurricane Matthew and other significant storms in 2016. The final estimate of incremental operation and maintenance and capital costs of $116 million was filed with the NCUC in September 2017. On July 10, 2017, the NCUC consolidated Duke Energy Progress' storm deferral request into the Duke Energy Progress rate case docket for decision.

On November 22, 2017, Duke Energy Progress and the Public Staff filed an Agreement and Stipulation of Partial Settlement resolving certain portions of the proceeding. Terms of the settlement included a return on equity of 9.9 percent and a capital structure of 52 percent equity and 48 percent debt. As a result of the settlement, in 2017 Duke Energy Progress recorded pretax charges totaling approximately $25 million to Impairment charges and Operation, maintenance and other on the Consolidated Statements of Operations, principally related to disallowances from rate base of certain projects at the Mayo and Sutton plants. On February 23, 2018, the NCUC issued an order approving the stipulation. The order also included the following material components not covered in the stipulation:

  • Recovery of the remaining $234 million of deferred coal ash basin closure costs over a five-year period with a return at Duke Energy Progress' WACC, excluding $10 million of retail deferred coal ash basin costs related to ash hauling at Duke Energy Progress' Asheville Plant;

  • Assessment of a $30 million management penalty ratably over a five-year period by reducing the annual recovery of the deferred coal ash costs;

  • Denial of Duke Energy Progress' request for recovery of future estimated ongoing annual coal ash costs of $129 million with approval to defer such costs with a return at Duke Energy Progress' WACC, to be considered for recovery in the next rate case; and

  • Approval to recover $51 million of the approximately $80 million deferred storm costs over a five-year period with amortization beginning in October 2016. The order did not allow the deferral of the associated capital costs or a return on the deferred balance during the deferral period.

The order also impacted certain amounts that were similarly recorded on Duke Energy Carolinas' Consolidated Balance Sheets. As a result of the order, Duke Energy Progress and Duke Energy Carolinas recorded pretax charges of $68 million and $14 million, respectively, in the first quarter of 2018 to Impairment charges, Operation, maintenance and other and Interest Expense on the Consolidated Statements of Operations. These charges primarily related to the coal ash basin disallowance and previously recognized return impacted by the coal ash management penalty and deferred storm cost adjustments. Revised customer rates became effective on March 16, 2018.

On May 15, 2018, the Public Staff filed a Notice of Cross Appeal to the North Carolina Supreme Court from the February 23, 2018, Order Accepting Stipulation, Deciding Contested Issues and Granting Partial Rate Increase issued by the NCUC. The Public Staff contend the commission’s order should be reversed and remanded, as it is affected by errors of law, and is unsupported by competent, material and substantial evidence in view of the entire record as submitted. The North Carolina Attorney General and Sierra Club have also filed Notices of Appeal to the North Carolina Supreme Court from the February 23, 2018, Order Accepting Stipulation, Deciding Contested Issues and Granting Partial Rate Increase. On November 29, 2018, the North Carolina Attorney General's Office filed a motion with the North Carolina Supreme Court requesting the court consolidate the Duke Energy Progress and Duke Energy Carolinas appeals and enter an order adopting the parties’ proposed briefing schedule as set out in the filing. On November 29, 2018, the North Carolina Supreme Court adopted a schedule for briefing set forth in the motion to consolidate the Duke Energy Progress and Duke Energy Carolinas appeals. The Appellee response briefs are due July 29, 2019. Duke Energy Progress cannot predict the outcome of this matter.

2016 South Carolina Rate Case

In December 2016, the PSCSC approved a rate case settlement agreement among the ORS, intervenors and Duke Energy Progress. Terms of the settlement agreement included an approximate $56 million increase in revenues over a two-year period. An increase of approximately $38 million in revenues was effective January 1, 2017, and an additional increase of approximately $19 million in revenues was effective January 1, 2018. Duke Energy Progress amortized approximately $19 million from the cost of removal reserve in 2017. Other settlement terms included a rate of return on equity of 10.1 percent, recovery of coal ash costs incurred from January 1, 2015, through June 30, 2016, over a 15-year period and ongoing deferral of allocated ash basin closure costs from July 1, 2016, until the next base rate case. The settlement also provides that Duke Energy Progress will not seek an increase in rates in South Carolina to occur prior to 2019, with limited exceptions.

2018 South Carolina Rate Case

On November 8, 2018, Duke Energy Progress filed an application with the PSCSC for a rate increase for retail customers of approximately $59 million, which represents an approximate 10.3 percent increase in annual base revenues. The rate increase is driven by capital investments and environmental compliance progress made by Duke Energy Progress since its previous rate case, including the further implementation of Duke Energy Progress’ generation modernization program, which consists of retiring, replacing and upgrading generation plants, investments in customer service technologies and continued investments in base work to maintain its transmission and distribution systems. The request includes net tax benefits of $15 million consisting of a $12 million increase due to the expiration of EDITs related to reductions in North Carolina state income taxes allocable to South Carolina and decreases resulting from the Tax Act of $17 million to reflect the change in ongoing tax expense, primarily the reduction in the federal income tax rate from 35 to 21 percent, and $10 million to return EDIT resulting from the federal tax rate change and deferred revenues since January 2018 related to the change.

Duke Energy Progress also requested approval of its proposed Grid Improvement Plan, approval of a Prepaid Advantage Program and a variety of accounting orders related to ongoing costs for environmental compliance, including recovery over a five-year period of $51 million of deferred coal ash related compliance costs, AMI deployment, grid investments between rate changes and regulatory asset treatment related to the retirement of a generating plant located in Asheville, North Carolina. Finally, Duke Energy Progress sought approval to establish a reserve and accrual for end of life nuclear costs for materials and supplies and nuclear fuel. An evidentiary hearing is scheduled to begin on April 11, 2019, and a decision and revised customer rates are expected by mid-2019. Duke Energy Progress cannot predict the outcome of this matter.

Western Carolinas Modernization Plan

On November 4, 2015, Duke Energy Progress announced a Western Carolinas Modernization Plan, which included retirement of the existing Asheville coal-fired plant, the construction of two 280-MW combined-cycle natural gas plants having dual-fuel capability, with the option to build a third natural gas simple cycle unit in 2023 based upon the outcome of initiatives to reduce the region's power demand. The plan also included upgrades to existing transmission lines and substations, installation of solar generation and a pilot battery storage project. These investments will be made within the next seven years. Duke Energy Progress is also working with the local natural gas distribution company to upgrade an existing natural gas pipeline to serve the natural gas plant.

On March 28, 2016, the NCUC issued an order approving a CPCN for the new combined-cycle natural gas plants, but denying the CPCN for the contingent simple cycle unit without prejudice to Duke Energy Progress to refile for approval in the future. On March 28, 2018, Duke Energy Progress filed an annual progress report for the construction of the combined-cycle plants with the NCUC, with an estimated cost of $893 million. Site preparation activities for the combined-cycle plants are complete and construction of these plants began in 2017, with an expected in-service date in late 2019.

On October 8, 2018, Duke Energy Progress filed an application with the NCUC for a CPCN to construct the Hot Springs Microgrid Solar and Battery Storage Facility. On November 30, 2018, the NCUC issued an order scheduling hearings, requiring filing of testimony, establishing discovery guidelines and requiring public notice. On February 7, 2019, Duke Energy Progress made a joint filing with the Public Staff, which accepted the Public Staff’s proposed conditions and requested that the NCUC cancel the evidentiary hearing. Duke Energy Progress cannot predict the outcome of this matter.

The carrying value of the 376-MW Asheville coal-fired plant, including associated ash basin closure costs, of $327 million and $385 million is included in Generation facilities to be retired, net on Duke Energy Progress' Consolidated Balance Sheets as of December 31, 2018, and 2017, respectively. Duke Energy Progress' request for a regulatory asset at the time of retirement with amortization over a 10-year period was approved by the NCUC on February 23, 2018.

Shearon Harris Nuclear Plant Expansion

In 2006, Duke Energy Progress selected a site at Harris to evaluate for possible future nuclear expansion. On February 19, 2008, Duke Energy Progress filed its COL application with the NRC for two Westinghouse AP1000 reactors at Harris, which the NRC docketed for review. On May 2, 2013, Duke Energy Progress filed a letter with the NRC requesting the NRC to suspend its review activities associated with the COL at the Harris site. The NCUC and PSCSC approved deferral of retail costs. Total deferred costs are approximately $43 million as of December 31, 2018, and are recorded in Regulatory assets on Duke Energy Progress’ Consolidated Balance Sheets. On November 17, 2016, the FERC approved Duke Energy Progress’ rate recovery request filing for the wholesale ratepayers’ share of the abandonment costs, including a debt-only return to be recovered through revised formula rates and amortized over a 15-year period beginning May 1, 2014. As part of the settlement agreement for the 2017 North Carolina Rate Case discussed above, Duke Energy Progress will amortize the regulatory asset over an eight-year period. NCUC approved the settlement on February 23, 2018.

South Carolina Petitions

On June 22, 2018, Duke Energy Progress filed a petition with the PSCSC seeking an accounting order authorizing Duke Energy Progress to adopt new depreciation rates, effective March 16, 2018, that reflect the results of Duke Energy Progress’ most recent depreciation study. Also on June 22, 2018, Duke Energy Progress filed a petition with the PSCSC requesting an accounting order to defer certain costs incurred in connection with the deployment of AMI, the ongoing deployment of Duke Energy Progress' new billing and Customer Information System, new depreciation rates and costs incurred in connection with the return of certain excess deferred state income taxes from North Carolina. These requests totaling approximately $20 million were approved on July 25, 2018.

FERC Form 1 Reporting Matter

On October 18, 2017, Fayetteville Public Works Commission (FPWC) filed with FERC a complaint against Duke Energy Progress. In the complaint, FPWC alleges that Duke Energy Progress’ change in its method of reporting materials and supplies inventory on FERC Form 1 for 2015 constituted a change in accounting practice that Duke Energy Progress was not permitted to implement without first obtaining FERC approval. On April 23, 2018, FERC issued an order finding that Duke Energy Progress’ new reporting methodology was not proper and required Duke Energy Progress to revise its FERC Form 1s beginning in 2014 and to issue refunds to formula rate customers. Duke Energy Progress estimates that these refunds will total approximately $14 million. On May 23, 2018, Duke Energy Progress filed a request for rehearing alleging that FERC’s order is incorrect. Duke Energy Progress revised its FERC Form 1 filings in June 2018. On August 31, 2018, Duke Energy Progress filed with FERC a refund report memorializing its payment of refunds to FPWC. Duke Energy Progress cannot predict the outcome of this matter.

Tax Act

As ordered by the NCUC on October 5, 2018, Duke Energy Progress filed a proposal on October 25, 2018, to adjust rates to reflect the reduction in federal corporate income tax rate from 35 to 21 percent for taxable years beginning after December 31, 2017, as outlined in the Tax Act. Duke Energy Progress proposed that this rate decrement be effective for service rendered on and after December 1, 2018. On November 28, 2018, the NCUC approved the proposal to implement the change in the federal corporate income tax rate and effective December 1, 2018, Duke Energy Progress implemented the rate reduction. Also, as ordered by the NCUC on October 5, 2018, Duke Energy Progress shall continue to hold in a deferred regulatory liability account the difference between revenues billed under the prior federal corporate income tax rate and the federal corporate income tax rate resulting from the Tax Act for the period January 1, 2018 through November 30, 2018. The disposition of such regulatory liability may be considered in Duke Energy Progress' next general rate case proceeding or in three years, whichever is sooner. EDIT related to the corporate income tax rate reduction shall be held in a deferred tax regulatory liability account until they can be addressed for ratemaking purposes in the next general rate case proceeding or in three years, whichever is sooner.

 

 

 

 

 

Duke Energy Florida

Regulatory Assets and Liabilities

The following tables present the regulatory assets and liabilities recorded on Duke Energy Florida's Consolidated Balance Sheets.

 

December 31,

 

Earns/Pays

Recovery/Refund

(in millions)

2018

2017

 

a Return

Period Ends

Regulatory Assets(a)

 

 

 

 

 

AROs – coal ash(c)

$

10

 

$

9

 

 

 

(b)

AROs – nuclear and other(c)

172

 

296

 

 

 

(b)

Accrued pension and OPEB(c)

532

 

476

 

 

X

(g)

Retired generation facilities(c)

219

 

216

 

 

X

(b)

Storm cost deferrals(c)(h)

382

 

376

 

 

(e)

2021

Nuclear asset securitized balance, net

1,093

 

1,142

 

 

 

2036

Hedge costs deferrals

20

 

30

 

 

 

2020

DSM/EE(c)

21

 

17

 

 

X

2023

Deferred fuel and purchased power(c)

203

 

219

 

 

(f)

2020

AMI(c)

60

 

75

 

 

X

2032

Other

176

 

36

 

 

(d)

(b)

Total regulatory assets

2,888

 

2,892

 

 

 

 

Less: current portion

434

 

389

 

 

 

 

Total noncurrent regulatory assets

$

2,454

 

$

2,503

 

 

 

 

Regulatory Liabilities(a)

 

 

 

 

 

Costs of removal(c)

$

257

 

$

415

 

 

(d)

(b)

Net regulatory liability related to income taxes(c)

847

 

948

 

 

 

(b)

Accrued pension and OPEB

56

 

 

 

X

(g)

Deferred fuel and purchased power(c)

16

 

 

 

(f)

2020

Other

20

 

18

 

 

(d)

(b)

Total regulatory liabilities

1,196

 

1,381

 

 

 

 

Less: current portion

102

 

74

 

 

 

 

Total noncurrent regulatory liabilities

$

1,094

 

$

1,307

 

 

 

 

(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) The expected recovery or refund period varies or has not been determined.

(c) Included in rate base.

(d) Certain costs earn a return.

(e) Earns a debt return/interest once collections begin.

(f) Earns commercial paper rate.

(g) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

(h) Balance includes $165 million for Hurricane Michael. Duke Energy Florida expects to seek recovery of these costs in the first half of 2019.

 

Storm Restoration Cost Recovery

In September 2017, Duke Energy Florida’s service territory suffered significant damage from Hurricane Irma, resulting in approximately 1 million customers experiencing outages. In the fourth quarter of 2017, Duke Energy Florida also incurred preparation costs related to Hurricane Nate. On December 28, 2017, Duke Energy Florida filed a petition with the FPSC to recover incremental storm restoration costs for Hurricane Irma and Hurricane Nate and to replenish the storm reserve. On February 6, 2018, the FPSC approved a stipulation that would apply tax savings resulting from the Tax Act toward storm costs effective January 2018 in lieu of implementing a storm surcharge. Storm costs are currently expected to be fully recovered by approximately mid-2021. On May 31, 2018, Duke Energy Florida filed a petition for approval of actual storm restoration costs and associated recovery process related to Hurricane Irma and Hurricane Nate. The petition is seeking the approval for the recovery in the amount of $510 million in actual recoverable storm restoration costs, including the replenishment of Duke Energy Florida’s storm reserve of $132 million, and the process for recovering these recoverable storm costs. On August 20, 2018, the FPSC approved Duke Energy Florida's unopposed Motion for Continuance filed August 17, 2018, to allow for an evidentiary hearing in this matter. On January 28, 2019, Duke Energy Florida made a supplemental filing to reduce the total storm cost recovery from $510 million to $508 million. The commission has scheduled the hearing to begin on May 21, 2019. At December 31, 2018, Duke Energy Florida's Consolidated Balance Sheets included approximately $217 million of recoverable costs under the FPSC's storm rule in Regulatory assets within Current Assets and Other Noncurrent Assets related to storm recovery for Hurricane Irma and Hurricane Nate. Duke Energy Florida cannot predict the outcome of this matter.

In October 2018, Duke Energy Florida’s service territory suffered damage when Hurricane Michael made landfall as a strong Category 4 hurricane with maximum sustained winds of 155 mph. The storm caused catastrophic damage from wind and storm surge, particularly from Panama City Beach to Mexico Beach, resulting in widespread outages and significant damage to transmission and distribution facilities across the central Florida Panhandle. In response to Hurricane Michael, Duke Energy Florida restored service to approximately 72,000 customers. Duke Energy Florida incurred approximately $200 million of costs resulting from the hurricane restoration efforts. Approximately $35 million of the costs are included in Net property, plant and equipment on the Consolidated Balance Sheets as of December 31, 2018. The remaining $165 million of costs represent recoverable costs under the FPSC’s storm rule and Duke Energy Florida's Open Access Transmission Tariff formula rates and are included in Regulatory assets within Other Noncurrent Assets on the Consolidated Balance Sheets as of December 31, 2018. Duke Energy Florida anticipates filing a petition with the FPSC in the first half of 2019 to recover these costs, consistent with the provisions in the 2017 Settlement. Duke Energy Florida cannot predict the outcome of this matter.

Tax Act

Pursuant to Duke Energy Florida's 2017 Settlement, on May 31, 2018, Duke Energy Florida filed a petition related to the Tax Act, which included revenue requirement impacts of annual tax savings of $134 million and estimated annual amortization of EDIT of $67 million for a total of $201 million. Of this amount, $50 million would be offset by accelerated depreciation of Crystal River 4 and 5 coal units and an estimated $151 million would be offset by Hurricane Irma storm cost recovery as explained in the Storm Restoration Cost Recovery section above. On December 27, 2018, Duke Energy Florida filed actual EDIT balances and amortization based on its 2017 filed tax return. This increased the revenue requirement impact of the amortization of EDIT by $4 million, from $67 million to $71 million. On January 8, 2019, the FPSC approved a joint motion by Duke Energy Florida and the Office of Public Counsel resolving all stipulated positions. As part of that stipulation, Duke Energy Florida will seek a Private Letter Ruling from the IRS on its treatment of COR as mostly protected by tax normalization rules. If the IRS rules that COR is not protected by tax normalization rules, then Duke Energy Florida will make a final adjustment to the amortization of EDIT and an adjustment to the storm recovery amount retroactive to January 2018. Duke Energy Florida cannot predict the outcome of this matter.

Citrus County CC

On October 2, 2014, the FPSC granted Duke Energy Florida a Determination of Need for the construction of a 1,640-MW combined-cycle natural gas plant in Citrus County, Florida. At that time, the estimated cost of the facility was $1.5 billion, including AFUDC. On May 5, 2015, the Florida Department of Environmental Protection approved Duke Energy Florida's Site Certification Application and construction began in October 2015. On July 10, 2018, the FPSC approved Duke Energy Florida's request to include the annual revenue requirement of $200 million for the new Citrus County combined-cycle units in base rates. The first 820-MW power block came on-line on October 26, 2018, and the rate increase for this unit was effective in December 2018. The second 820-MW power block came on-line November 24, 2018. The rate increase for the second unit was effective in January 2019. The ultimate cost of the facility is estimated to be $1.6 billion, and Duke Energy Florida recorded Impairment charges on Duke Energy’s Consolidated Statements of Operations of $60 million in the fourth quarter of 2018 for the overrun, which may change in light of recoveries from the EPC contractor. The plant began receiving natural gas from the Sabal Trail pipeline in August 2018. As a result of the combined-cycle natural gas plant coming on-line, Crystal River coal-fired units 1 and 2 were retired in December 2018. See Note 5 for additional information on Citrus.

 

 

Solar Base Rate Adjustment

On July 31, 2018, Duke Energy Florida petitioned the FPSC to include in base rates the revenue requirements for its first two solar generation projects, the Hamilton Project and the Columbia Project, as authorized by the 2017 Settlement. The Hamilton Project, which was placed into service on December 22, 2018, has an annual retail revenue requirement of $15 million and the increase was effective in January 2019. The Columbia Project has a projected annual revenue requirement of $14 million and a projected in-service date in early 2020; the associated rate increase would take place with the first month’s billing cycle after the Columbia Project goes into service. At its October 30, 2018, Agenda Conference, the FPSC approved the rate increase related to the Hamilton Project to go into effect beginning with the first billing cycle in January 2019 under its file and suspend authority. Rates are subject to true up pending the outcome of the final hearing, which is scheduled to take place on April 2, 2019. Duke Energy Florida cannot predict the outcome of this matter.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Duke Energy Ohio

Regulatory Assets and Liabilities

The following tables present the regulatory assets and liabilities recorded on Duke Energy Ohio's Consolidated Balance Sheets.

 

December 31,

 

Earns/Pays

Recovery/Refund

(in millions)

2018

2017

 

a Return

Period Ends

Regulatory Assets(a)

 

 

 

 

 

AROs – coal ash

$

20

 

$

17

 

 

X

(b)

Accrued pension and OPEB

146

 

139

 

 

 

(g)

Storm cost deferrals

4

 

5

 

 

 

2023

Hedge costs deferrals

5

 

6

 

 

 

(b)

DSM/EE

10

 

18

 

 

(f)

(e)

Grid modernization

31

 

39

 

 

X

(e)

Vacation accrual

5

 

5

 

 

 

2019

Deferred fuel and purchased power

2

 

 

 

 

2019

PISCC and deferred operating expenses(c)

17

 

19

 

 

X

2083

Transmission expansion obligation

43

 

50

 

 

 

(e)

MGP

99

 

91

 

 

 

(b)

AMI

46

 

6

 

 

 

(b)

East Bend deferrals

47

 

45

 

 

X

(b)

Deferred pipeline integrity costs

14

 

12

 

 

X

(b)

Other

75

 

42

 

 

 

(b)

Total regulatory assets

564

 

494

 

 

 

 

Less: current portion

33

 

49

 

 

 

 

Total noncurrent regulatory assets

$

531

 

$

445

 

 

 

 

Regulatory Liabilities(a)

 

 

 

 

 

Costs of removal

$

126

 

$

189

 

 

 

(d)

Net regulatory liability related to income taxes

678

 

688

 

 

 

(b)

Accrued pension and OPEB

18

 

16

 

 

 

(g)

Other

75

 

34

 

 

 

(b)

Total regulatory liabilities

897

 

927

 

 

 

 

Less: current portion

57

 

36

 

 

 

 

Total noncurrent regulatory liabilities

$

840

 

$

891

 

 

 

 

(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) The expected recovery or refund period varies or has not been determined.

(c) Included in rate base.

(d) Recovery over the life of the associated assets.

(e) Recovered via a rider mechanism.

(f) Includes incentives on DSM/EE investments.

(g) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

2017 Electric Security Plan

On June 1, 2017, Duke Energy Ohio filed with the PUCO a request for a standard service offer in the form of an ESP. On February 15, 2018, the procedural schedule was suspended to facilitate ongoing settlement discussions. On April 13, 2018, Duke Energy Ohio filed a Motion to consolidate this proceeding with several other cases currently pending before the PUCO, including, but not limited to, its Electric Base Rate Case. Additionally, on April 13, 2018, Duke Energy Ohio, along with certain intervenors, filed a Stipulation and Recommendation (Stipulation) with the PUCO resolving certain issues in this proceeding. The term of the ESP would be from June 1, 2018, to May 31, 2025, and includes continuation of market-based customer rates through competitive procurement processes for generation, continuation and expansion of existing rider mechanisms and proposed new rider mechanisms relating to regulatory mandates, costs incurred to enhance the customer experience and transform the grid and a service reliability rider for vegetation management. The Stipulation establishes a regulatory model for the next seven years via the approval of the ESP and continues the current model for procuring supply for non-shopping customers, including recovery mechanisms. On December 19, 2018, the PUCO approved the Stipulation without material modification. Several parties have filed applications for rehearing. On February 6, 2019, the PUCO granted the parties rehearing. Duke Energy Ohio cannot predict the outcome of this matter.

Electric Base Rate Case

Duke Energy Ohio filed with the PUCO an electric distribution base rate case application and supporting testimony in March 2017. Duke Energy Ohio requested an estimated annual increase of approximately $15 million and a return on equity of 10.4 percent. The application also included requests to continue certain current riders and establish new riders. On September 26, 2017, the PUCO staff filed a report recommending a revenue decrease between approximately $18 million and $29 million and a return on equity between 9.22 percent and 10.24 percent. On April 13, 2018, Duke Energy Ohio filed a Motion to consolidate this proceeding with several other cases pending before the PUCO. On April 13, 2018, Duke Energy Ohio, along with certain intervenors, filed the Stipulation with the PUCO resolving numerous issues including those in this base rate proceeding. Major components of the Stipulation related to the base distribution rate case include a $19 million decrease in annual base distribution revenue with a return on equity unchanged from the current rate of 9.84 percent based upon a capital structure of 50.75 percent equity and 49.25 percent debt. Upon approval of new rates, Duke Energy Ohio's rider for recovering its initial SmartGrid implementation ends as these costs will be recovered through base rates. The Stipulation also renews 14 existing riders, some of which were included in the company's ESP, and adds two new riders including the Enhanced Service Reliability Rider to recover vegetation management costs not included in base rates, up to $10 million per year (operation and maintenance only) and the PowerForward Rider to recover costs incurred to enhance the customer experience and further transform the grid (operation and maintenance and capital). In addition to the changes in revenue attributable to the Stipulation, Duke Energy Ohio’s capital-related riders, including the Distribution Capital Investments Rider, began to reflect the lower federal income tax rate associated with the Tax Act with updates to customers’ bills beginning April 1, 2018. This change reduces electric revenue by approximately $20 million on an annualized basis. On December 19, 2018, the PUCO approved the Stipulation without material modification. New base rates were implemented effective January 2, 2019. Several parties have filed applications for rehearing. On February 6, 2019, the PUCO granted the parties rehearing. Duke Energy Ohio cannot predict the outcome of this matter.

Ohio Valley Electric Corporation

On March 31, 2017, Duke Energy Ohio filed for approval to adjust its existing price stabilization rider (Rider PSR), which is currently set at zero dollars, to pass through net costs related to its contractual entitlement to capacity and energy from the generating assets owned by OVEC. Duke Energy Ohio sought deferral authority for net costs incurred from April 1, 2017, until the new rates under Rider PSR are put into effect. On April 13, 2018, Duke Energy Ohio filed a Motion to consolidate this proceeding with several other cases currently pending before the PUCO. Also on April 13, 2018, Duke Energy Ohio, along with certain intervenors, filed a Stipulation with the PUCO resolving numerous issues including those related to Rider PSR. The Stipulation activates Rider PSR for recovery of net costs incurred from January 1, 2018 through May 2025. On December 19, 2018, the PUCO approved the Stipulation without material modification. Several parties have filed applications for rehearing. On February 6, 2019, the PUCO granted the parties rehearing. Duke Energy Ohio cannot predict the outcome of this matter. See Note 17 for additional discussion of Duke Energy Ohio's ownership interest in OVEC.

 

 

 

 

 

Tax Act – Ohio

On July 25, 2018, Duke Energy Ohio filed an application to establish a new rider to implement the benefits of the Tax Act for electric distribution customers. Duke Energy Ohio requested commission approval to implement the rider effective October 1, 2018, as a credit to all distribution customers based upon a percent reduction to Duke Energy Ohio’s distribution rates. The new rider will flow through to customers the benefit of the lower statutory federal tax rate from 35 to 21 percent since January 1, 2018, all future benefits of the lower tax rates and a full refund of deferred income taxes collected at the higher tax rates in prior years. Deferred income taxes subject to normalization rules will be refunded consistent with federal law and deferred income taxes not subject to normalization rules will be refunded over a 10-year period. Duke Energy Ohio's transmission rates reflect lower federal income tax but guidance from FERC on amortization of both protected and unprotected transmission-related EDITs is still pending. On October 24, 2018, the PUCO issued a Finding and Order that, among other things, directed all utilities over which the commission has rate-making authority to file an application to pass the benefits of the Tax Act to customers by January 1, 2019, unless otherwise exempted or directed by the PUCO. Duke Energy Ohio's July 25, 2018, filing for electric distribution operations is consistent with the commission's October 24, 2018, Finding and Order and no further action is needed. On February 20, 2019, the PUCO approved the application without material modification. Rates will be effective March 1, 2019. On December 21, 2018, Duke Energy Ohio filed an application to change its base rates and establish a new rider to implement the benefits of the Tax Act for natural gas customers. Duke Energy Ohio requested commission approval to implement the changes and rider effective April 1, 2019. The new rider will flow through to customers the benefit of the lower statutory federal tax rate from 35 to 21 percent since January 1, 2018, all future benefits of the lower tax rates and a full refund of deferred income taxes collected at the higher tax rates in prior years. Deferred income taxes subject to normalization rules will be refunded consistent with federal law and deferred income taxes not subject to normalization rules will be refunded over a 10-year period. The PUCO has not yet ruled on the application for changes for natural gas customers. Duke Energy Ohio cannot predict the outcome of this matter.

Energy Efficiency Cost Recovery

On March 28, 2014, Duke Energy Ohio filed an application for recovery of program costs, lost distribution revenue and performance incentives related to its energy efficiency and peak demand reduction programs. These programs are undertaken to comply with environmental mandates set forth in Ohio law. The PUCO approved Duke Energy Ohio’s application but found that Duke Energy Ohio was not permitted to use banked energy savings from previous years in order to calculate the amount of allowed incentive. This conclusion represented a change to the cost recovery mechanism that had been agreed upon by intervenors and approved by the PUCO in previous cases. The PUCO granted the applications for rehearing filed by Duke Energy Ohio and an intervenor. On January 6, 2016, Duke Energy Ohio and the PUCO Staff entered into a stipulation, pending the PUCO's approval, to resolve issues related to performance incentives and the PUCO Staff audit of 2013 costs, among other issues. In December 2015, based upon the stipulation, Duke Energy Ohio re-established approximately $20 million of the revenues that had been previously reversed. On October 26, 2016, the PUCO issued an order approving the stipulation without modification. In December 2016, the PUCO granted the intervenors request for rehearing for the purpose of further review. Duke Energy Ohio cannot predict the outcome of this matter.

On June 15, 2016, Duke Energy Ohio filed an application for approval of a three-year energy efficiency and peak demand reduction portfolio of programs. A stipulation and modified stipulation were filed on December 22, 2016, and January 27, 2017, respectively. Under the terms of the stipulations, which included support for deferral authority of all costs and a cap on shared savings incentives, Duke Energy Ohio has offered its energy efficiency and peak demand reduction programs throughout 2017. On February 3, 2017, Duke Energy Ohio filed for deferral authority of its costs incurred in 2017 in respect of its proposed energy efficiency and peak demand reduction portfolio. On September 27, 2017, the PUCO issued an order approving a modified stipulation. The modifications impose an annual cap of approximately $38 million on program costs and shared savings incentives combined, but allowed for Duke Energy Ohio to file for a waiver of costs in excess of the cap in 2017. The PUCO approved the waiver request for 2017 up to a total cost of $56 million. On November 21, 2017, the PUCO granted Duke Energy Ohio's and intervenor's applications for rehearing of the September 27, 2017, order. On January 10, 2018, the PUCO denied the Ohio Consumers' Counsel’s application for rehearing of the PUCO order granting Duke Energy Ohio's waiver request; however, a decision on Duke Energy Ohio's application for rehearing remains pending. Duke Energy Ohio cannot predict the outcome of this matter.

2014 Electric Security Plan

In April 2015, the PUCO modified and approved Duke Energy Ohio's proposed ESP, with a three-year term and an effective date of June 1, 2015. The PUCO approved a competitive procurement process for SSO load, a distribution capital investment rider (Rider DCI) and a tracking mechanism for incremental distribution expenses caused by major storms. The PUCO also approved a placeholder tariff for a price stabilization rider, but denied Duke Energy Ohio's specific request to include Duke Energy Ohio's entitlement to generation from OVEC in the rider at this time; however, the order allows Duke Energy Ohio to submit additional information to request recovery in the future. On May 4, 2015, Duke Energy Ohio filed an application for rehearing requesting the PUCO to modify or amend certain aspects of the order. On May 28, 2015, the PUCO granted all applications for rehearing filed in the case for future consideration. On March 21, 2018, the PUCO issued an order denying Duke Energy Ohio's issues on rehearing. On April 20, 2018, Duke Energy Ohio filed a second application for rehearing based upon the commission’s March 21, 2018, Order. On May 16, 2018, the commission issued its third Entry on Rehearing granting in part, and denying in part, Duke Energy Ohio’s rehearing request.

On March 9, 2018, Duke Energy Ohio filed a motion to extend its then-current ESP, including all terms and conditions thereof, pending approval of a new ESP. On May 30, 2018, the PUCO granted the request, with modification. Specifically, the PUCO did not extend the cap applicable to Rider DCI beyond July 31, 2018. Duke Energy Ohio sought rehearing of this finding. On July 25, 2018, the PUCO granted the request and allowed a continuing cap on recovery under Rider DCI. On August 24, 2018, OMA and OCC filed an Application for Rehearing of the commission's decision. Duke Energy Ohio filed a Memorandum Contra OCC's request for rehearing of the commission's continuation of Rider DCI on September 4, 2018. On September 19, 2018, the PUCO issued an Order granting rehearing on the matter for further consideration. Duke Energy Ohio cannot predict the outcome of this matter.

On May 21, 2018, the Ohio Manufacturers' Association (OMA) filed a notice of appeal of PUCO's approval of Duke Energy Ohio’s ESP with the Ohio Supreme Court, challenging PUCO's approval of Duke Energy Ohio’s Price Stability Rider as a placeholder and its Rider DCI to recover incremental revenue requirement for distribution capital since Duke Energy Ohio’s last base rate case. On July 16, 2018, the Office of the Ohio Consumers' Counsel (OCC) filed its own appeal of Duke Energy Ohio’s ESP with the Ohio Supreme Court raising similar issues to that of the OMA. Duke Energy Ohio filed a Motion to Intervene in the two Ohio Supreme Court appeals. OMA's Supreme Court brief was filed on August 20, 2018. PUCO submitted its brief on October 26, 2018, and Duke Energy Ohio filed its brief on October 29, 2018. The OCC’s Supreme Court brief was filed on October 15, 2018. Duke Energy Ohio filed its brief on December 20, 2018. The PUCO submitted its brief on December 21, 2018. Duke Energy Ohio cannot predict the outcome of this matter.

Natural Gas Pipeline Extension

Duke Energy Ohio is proposing to install a new natural gas pipeline (the Central Corridor Project) in its Ohio service territory to increase system reliability and enable the retirement of older infrastructure. Duke Energy Ohio currently estimates the pipeline development costs and construction activities will range from $163 million to $245 million in direct costs (excluding overheads and AFUDC). On January 20, 2017, Duke Energy Ohio filed an amended application with the Ohio Power Siting Board (OPSB) for approval of one of two proposed routes. A public hearing was held on June 15, 2017. In April 2018, Duke Energy Ohio filed a motion with OPSB to establish a procedural schedule and filed supplemental information supporting its application. On December 18, 2018, the OPSB established a procedural schedule that includes a local public hearing on March 21, 2019, and an evidentiary hearing starting on April 9, 2019. If approved, construction of the pipeline extension is expected to be completed before the 2021/2022 winter season. Duke Energy Ohio cannot predict the outcome of this matter.

2012 Natural Gas Rate Case/MGP Cost Recovery

On November 13, 2013, the PUCO issued an order approving a settlement of Duke Energy Ohio’s natural gas base rate case and authorizing the recovery of costs incurred between 2008 and 2012 for environmental investigation and remediation of two former MGP sites. The PUCO order also authorized Duke Energy Ohio to continue deferring MGP environmental investigation and remediation costs incurred subsequent to 2012 and to submit annual filings to adjust the MGP rider for future costs. Intervening parties appealed this decision to the Ohio Supreme Court and on June 29, 2017, the Ohio Supreme Court issued its decision affirming the PUCO order. Appellants filed a request for reconsideration, which was denied on September 27, 2017. This matter is now final.

The PUCO order also contained conditional deadlines for completing the MGP environmental investigation and remediation costs at the MGP sites. As of December 31, 2018, Duke Energy Ohio had approximately $24 million for future remediation costs expected to be incurred at the East End site and approximately $23 million for future remediation costs expected to be incurred at the West End site included in Regulatory assets within Other Noncurrent Assets on the Consolidated Balance Sheets.

 

 

 

 

 

 

 

 

 

Duke Energy Kentucky Electric Rate Case

On September 1, 2017, Duke Energy Kentucky filed a rate case with the KPSC requesting an increase in electric base rates of approximately $49 million, which represents an approximate 15 percent increase on the average customer bill. Subsequent to the filing, Duke Energy Kentucky adjusted the requested amount to $30.1 million, in part to reflect the benefits of the Tax Act, representing an approximate 9 percent increase on the average customer bill. The rate increase was driven by increased investment in utility plant, increased operations and maintenance expenses and recovery of regulatory assets. The application also includes requests to implement an Environmental Surcharge Mechanism to recover environmental costs not recovered in base rates, to establish a Distribution Capital Investment Rider to recover incremental costs of specific programs, to establish a FERC Transmission Cost Reconciliation Rider to recover escalating transmission costs and to modify existing Profit Sharing Mechanism to increase customers' share of proceeds from the benefits of owning generation and to mitigate shareholder risks associated with that generation. An evidentiary hearing concluded on March 8, 2018, and the KPSC issued an order on April 13, 2018. Major components of the Order include approval of an $8 million increase in base rates with a return on equity at 9.725 percent based upon a capital structure of 49 percent equity on a total allocable capitalization of approximately $650 million. The Order approved the Environmental Surcharge Mechanism Rider and in June 2018 recovery began of capital-related environmental costs, including costs related to ash and ash disposal, and environmental operation and maintenance expenses formerly recovered in base rates, including expenses for environmental reagents and emission allowances. The incremental revenue from this rider will be approximately $13 million on an annualized basis. The order settles all issues associated with the Tax Act as it relates to the electric business by lowering the income tax component of the revenue requirement and refunding protected EDIT under allowable normalization rules and unprotected EDIT over 10 years. The Order denied requests to implement riders for certain transmission costs and distribution capital investments. Duke Energy Kentucky implemented new base rates on May 1, 2018. On May 3, 2018, Duke Energy Kentucky filed an application for rehearing on certain aspects of the order; on May 23, 2018, the KPSC granted a rehearing. On October 2, 2018, the KPSC issued its rehearing order correcting certain findings in its initial order and making additional changes that are immaterial to the company's earnings.

Duke Energy Kentucky Natural Gas Base Rate Case

On August 31, 2018, Duke Energy Kentucky filed an application with the KPSC requesting an increase in natural gas base rates of approximately $11 million, an approximate 11.1 percent average increase across all customer classes. The increase is net of approximately $5 million in annual savings as a result of the Tax Act. The drivers for this case are capital invested since Duke Energy Kentucky’s last rate case in 2009. Duke Energy Kentucky is also seeking implementation of a Weather Normalization Adjustment Mechanism, amortization of regulatory assets and to implement the impacts of the Tax Act, prospectively. On January 30, 2019, Duke Energy Kentucky entered into a settlement agreement with the Attorney General of Kentucky, the only intervenor in the case, which if approved would resolve the matter. The settlement provides for an approximate $7 million increase and approval of the proposed Weather Normalization Mechanism. A hearing was held on February 5, 2019. A ruling is expected in late first quarter 2019. Duke Energy Kentucky cannot predict the outcome of this matter.

FERC 494 Refund of Regional Transmission Enhancement Projects

FERC Order No. 494 Settlement Agreement (FERC 494 Settlement Agreement) was entered into by most of the PJM transmission owners, including Duke Energy Ohio and Duke Energy Kentucky, and the PJM state regulatory commissions approximately two years ago and was planned to be effective on January 1, 2016; however, it was not approved by FERC until May 31, 2018. The FERC 494 Settlement Agreement was due to the Seventh Circuit Court of Appeals finding that FERC had failed to adequately justify the costs that the customers in the western part of PJM were being charged for high voltage transmission projects, or Regional Transmission Expansion Plan (RTEP) projects (500 kV and above) built in the east. These costs were being allocated to all PJM customers on a load-ratio share basis but the court determined that these costs were not justifiable to customers in the west, including Duke Energy Ohio and Duke Energy Kentucky, that did not benefit from the RTEP projects. Costs for the periods 2012 through 2015 are expected to be refunded to Duke Energy Ohio and Duke Energy Kentucky on a monthly basis through December 2025. The refund amount for similar costs incurred beginning in 2016 through June 30, 2018, prior to the change in cost allocation by PJM was determined in the third quarter of 2018 and these amounts will be refunded over a 12-month period beginning in July 2018. These refunds, totaling approximately $47 million for Duke Energy Ohio and Duke Energy Kentucky, have been recorded to Operation, maintenance and other on the Consolidated Statements of Operations for the year ended December 31, 2018.

Regional Transmission Organization Realignment

Duke Energy Ohio, including Duke Energy Kentucky, transferred control of its transmission assets from MISO to PJM, effective December 31, 2011. The PUCO approved a settlement related to Duke Energy Ohio’s recovery of certain costs of the RTO realignment via a non-bypassable rider. Duke Energy Ohio is allowed to recover all MTEP costs directly or indirectly charged to Ohio customers. The KPSC also approved a request to effect the RTO realignment, subject to a commitment not to seek double recovery in a future rate case of the transmission expansion fees that may be charged by MISO and PJM in the same period or overlapping periods.

The following table provides a reconciliation of the beginning and ending balance of Duke Energy Ohio’s recorded liability for its exit obligation and share of MTEP costs recorded in Other within Current Liabilities and Other Noncurrent Liabilities on the Consolidated Balance Sheets. The retail portions of MTEP costs billed by MISO are recovered by Duke Energy Ohio through a non-bypassable rider. As of December 31, 2018, and 2017, $43 million and $50 million, respectively, are recorded in Regulatory assets on Duke Energy Ohio's Consolidated Balance Sheets.

 

 

 

Provisions/

 

Cash

 

 

(in millions)

December 31, 2017

 

Adjustments

 

Reductions

 

December 31, 2018

Duke Energy Ohio

$

66

 

 

$

(4

)

 

$

(4

)

 

$

58

 

 

Duke Energy Indiana

Regulatory Assets and Liabilities

The following tables present the regulatory assets and liabilities recorded on Duke Energy Indiana's Consolidated Balance Sheets.

 

December 31,

 

Earns/Pays

Recovery/Refund

(in millions)

2018

2017

 

a Return

Period Ends

Regulatory Assets(a)

 

 

 

 

 

AROs – coal ash

$

450

 

$

380

 

 

 

(b)

Accrued pension and OPEB

222

 

197

 

 

 

(f)

Retired generation facilities(c)

57

 

65

 

 

X

2026

Hedge costs deferrals

24

 

25

 

 

 

(b)

DSM/EE

14

 

21

 

 

(e)

(e)

Vacation accrual

11

 

11

 

 

 

2019

Deferred fuel and purchased power

40

 

18

 

 

 

2019

PISCC and deferred operating expenses(c)

233

 

274

 

 

X

(b)

AMI(c)

18

 

21

 

 

X

(b)

Other

88

 

131

 

 

 

(b)

Total regulatory assets

1,157

 

1,143

 

 

 

 

Less: current portion

175

 

165

 

 

 

 

Total noncurrent regulatory assets

$

982

 

$

978

 

 

 

 

Regulatory Liabilities(a)

 

 

 

 

 

Costs of removal

$

628

 

$

644

 

 

 

(d)

Net regulatory liability related to income taxes

1,009

 

998

 

 

 

(b)

Amounts to be refunded to customers

1

 

10

 

 

 

2019

Accrued pension and OPEB

67

 

64

 

 

 

(f)

Other

42

 

31

 

 

 

(b)

Total regulatory liabilities

1,747

 

1,747

 

 

 

 

Less: current portion

25

 

24

 

 

 

 

Total noncurrent regulatory liabilities

$

1,722

 

$

1,723

 

 

 

 

(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) The expected recovery or refund period varies or has not been determined.

(c) Included in rate base.

(d) Recovery over the life of the associated assets.

(e) Includes incentives on DSM/EE investments and is recovered through a tracker mechanism over a two-year period.

(f) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

FERC Transmission Return on Equity Complaint

Customer groups have filed with the FERC complaints against Midcontinent Independent System Operator, Inc. (MISO) and its transmission-owning members, including Duke Energy Indiana, alleging, among other things, that the current base rate of return on equity earned by MISO transmission owners of 12.38 percent is unjust and unreasonable. The complaints claim, among other things, that the current base rate of return on equity earned by MISO transmission owners should be reduced to 8.67 percent. On January 5, 2015, the FERC issued an order accepting the MISO transmission owners' adder of 0.50 percent to the base rate of return on equity based on participation in an RTO subject to it being applied to a return on equity that is shown to be just and reasonable in the pending return on equity complaints. On December 22, 2015, the presiding FERC ALJ in the first complaint issued an Initial Decision in which the base rate of return on equity was set at 10.32 percent. On September 28, 2016, the Initial Decision in the first complaint was affirmed by FERC, but is subject to rehearing requests. On June 30, 2016, the presiding FERC ALJ in the second complaint issued an Initial Decision setting the base rate of return on equity at 9.70 percent. The Initial Decision in the second complaint is pending FERC review. On April 14, 2017, the U.S. Court of Appeals for the District of Columbia Circuit, in Emera Maine v. FERC, reversed and remanded certain aspects of the methodology employed by FERC to establish rates of return on equity. On October 16, 2018, FERC issued an order in response to the Emera remand proceeding proposing a new method for determining whether an existing return on equity is unjust and unreasonable, and a new process for determining a just and reasonable return on equity. On November 14, 2018, FERC directed parties to the MISO complaints to file briefs on how the new process for determining return on equity proposed in the Emera proceeding should be applied to the complaints involving the MISO transmission owners’ return on equity. Initial briefs were filed on February 13, 2019, and reply briefs will be due April 10, 2019. Duke Energy Indiana currently believes these matters will not have a material impact on its results of operations, cash flows and financial position.

Benton County Wind Farm Dispute

On December 16, 2013, BCWF filed a lawsuit against Duke Energy Indiana seeking damages for past generation losses alleging Duke Energy Indiana violated its obligations under a 2006 PPA by refusing to offer electricity to the market at negative prices. Damage claims continue to increase during times that BCWF is not dispatched. Under 2013 revised MISO market rules, Duke Energy Indiana is required to make a price offer to MISO for the power it proposes to sell into MISO markets and MISO determines whether BCWF is dispatched. Because market prices would have been negative due to increased market participation, Duke Energy Indiana determined it would not bid at negative prices in order to balance customer needs against BCWF's need to run. BCWF contends Duke Energy Indiana must bid at the lowest negative price to ensure dispatch, while Duke Energy Indiana contends it is not obligated to bid at any particular price, that it cannot ensure dispatch with any bid and that it has reasonably balanced the parties' interests. On July 6, 2015, the U.S. District Court for the Southern District of Indiana entered judgment against BCWF on all claims. BCWF appealed the decision and on December 9, 2016, the appeals court ruled in favor of BCWF. Duke Energy Indiana recorded an obligation and a regulatory asset related to the settlement amount in fourth quarter 2016. On June 30, 2017, the parties finalized a settlement agreement. Terms of the settlement included Duke Energy Indiana paying $29 million for back damages. Additionally, the parties agreed on the method by which the contract will be bid into the market in the future. The settlement amount was paid in June 2017. The IURC issued an order on September 27, 2017, approving recovery of the settlement amount through Duke Energy Indiana's fuel clause. The IURC order has been appealed to the Indiana Court of Appeals. On May 21, 2018, the Indiana Court of Appeals upheld the commission's decision. The appellants have requested rehearing at the Indiana Court of Appeals. The Indiana Court of Appeals denied the request for rehearing. The appellants have requested transfer to the Indiana Supreme Court, including briefs in support from environmental groups. The Indiana Supreme Court denied transfer concluding this matter in favor of Duke Energy Indiana.

Edwardsport Integrated Gasification Combined Cycle Plant

On September 20, 2018, Duke Energy Indiana, the Indiana Office of Utility Consumer Counselor, the Duke Industrial Group and Nucor Steel – Indiana entered into a settlement agreement to resolve IGCC ratemaking issues for calendar years 2018 and 2019. The agreement will remain in effect until new rates are established in Duke Energy Indiana's next base rate case, which is expected to be filed in mid-2019 with rates effective in mid-2020. It addresses the pending Edwardsport filing at the commission and eliminates the need for future filings until the overall rate case. This settlement includes caps on Duke Energy Indiana’s retail operating expenses for 2018 and 2019, reduces Duke Energy Indiana's regulatory asset by $30 million (with a corresponding reduction of the amount of amortization of the regulatory asset included in rates by $10 million annually beginning with the implementation of final IGCC 17 rates), and provides funding for low-income assistance and clean energy projects. Duke Energy Indiana recognized pretax impairment and related charges of $32 million in the third quarter of 2018. The settlement is subject to IURC approval. An evidentiary hearing was held December 2018 and an IURC Order is expected in March 2019. Duke Energy Indiana cannot predict the outcome of this matter.

 

 

Tax Act

On June 27, 2018, Duke Energy Indiana, the Indiana Office of Utility Consumer Counselor, the Indiana Industrial Group and Nucor Steel – Indiana filed testimony consistent with their Stipulation and Settlement Agreement (Settlement Agreement) in the federal tax act proceeding with the IURC. The Settlement Agreement outlines how Duke Energy Indiana will implement the impacts of the Tax Act. Material components of the Settlement Agreement were as follows:

  • Riders to reflect the change in the statutory federal tax rate from 35 to 21 percent as they are filed in 2018;

  • Base rates to reflect the change in the statutory federal tax rate from 35 to 21 percent upon IURC approval, but no later than September 1, 2018;

  • Duke Energy Indiana to continue to defer protected federal EDIT until January 1, 2020, at which time it will be returned to customers according to the Average Rate Assumption Method required by the Internal Revenue Service over approximately 26 years; and

  • Duke Energy Indiana to begin returning unprotected federal EDIT upon IURC approval, over 10 years. In order to mitigate the negative impacts to cash flow and credit metrics, the Settlement Agreement allows Duke Energy Indiana to return $7 million per year over the first five years, with a step up to $35 million per year in the following five years.

On August 22, 2018, the IURC approved the settlement and rates were adjusted effective September 1, 2018.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Piedmont

Regulatory Assets and Liabilities

The following tables present the regulatory assets and liabilities recorded on Piedmont's Consolidated Balance Sheets.

 

December 31,

 

Earns/Pays

Recovery/Refund

(in millions)

2018

2017

 

a Return

Period Ends

Regulatory Assets(a)

 

 

 

 

 

AROs – other

$

19

 

$

15

 

 

 

(d)

Accrued pension and OPEB(c)

99

 

91

 

 

X

(f)

Derivatives – gas supply contracts(e)

141

 

142

 

 

 

 

Vacation accrual

12

 

10

 

 

 

 

Deferred pipeline integrity costs(c)

51

 

42

 

 

X

(b)

Amount due from customers

24

 

64

 

 

X

(b)

Other

11

 

14

 

 

 

(b)

Total regulatory assets

357

 

378

 

 

 

 

Less: current portion

54

 

95

 

 

 

 

Total noncurrent regulatory assets

$

303

 

$

283

 

 

 

 

Regulatory Liabilities(a)

 

 

 

 

 

Costs of removal

$

564

 

$

544

 

 

 

(d)

Net regulatory liability related to income taxes

579

 

597

 

 

 

(b)

Accrued pension and OPEB(c)

1

 

 

 

X

(f)

Amount due to customers

33

 

 

 

X

(b)

Other

41

 

3

 

 

 

(b)

Total regulatory liabilities

1,218

 

1,144

 

 

 

 

Less: current portion

37

 

3

 

 

 

 

Total noncurrent regulatory liabilities

$

1,181

 

$

1,141

 

 

 

 

(a) Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) The expected recovery or refund period varies or has not been determined.

(c) Included in rate base.

(d) Recovery over the life of the associated assets.

(e) Balance will fluctuate with changes in the market. Current contracts extend into 2031.

(f) Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

South Carolina Rate Stabilization Adjustment Filing

On June 15, 2018, Piedmont filed with the PSCSC under the South Carolina Rate Stabilization Act its quarterly monitoring report for the 12-month period ending March 31, 2018. The filing included a revenue deficiency calculation and tariff rates in order to permit Piedmont the opportunity to earn the rate of return on common equity established in its last general rate case. The filing also incorporated the impacts of the Tax Act by lowering the income tax component of the revenue requirement, refunding protected EDIT under allowable normalization rules, unprotected EDIT and amounts over collected from the customers from January 1, 2018, through the end of the review period for this proceeding. A settlement agreement reached between Piedmont and ORS was filed with the PSCSC on September 14, 2018, and approved by the PSCSC on October 3, 2018. Terms of the settlement include implementation of rates for the 12-month period beginning November 2018 with a return on equity of 10.2 percent.

North Carolina Integrity Management Rider Filing

In October 2018, Piedmont filed a petition under the IMR mechanism to collect an additional $10 million in annual revenues, effective December 2018, based on the eligible capital investments closed to integrity and safety projects over the six-month period ended September 30, 2018. On November 27, 2018, the NCUC approved the requested rate adjustment.

In May 2018, Piedmont filed, and the NCUC approved, a petition under the IMR mechanism to update rates, effective June 2018, based on the eligible capital investments closed to integrity and safety projects over the six-month period ending March 31, 2018, and the decrease in the corporate federal income tax rate effective January 1, 2018. The combined effect of the update was a reduction to annual revenues of approximately $6 million.

Tennessee Integrity Management Rider Filing

In November 2018, Piedmont filed a petition with the TPUC under the IMR mechanism to collect an additional $3 million in annual revenues, effective January 2019, based on the eligible capital investments closed to integrity and safety projects over the 12-month period ending October 31, 2018. A hearing on this matter is scheduled for March 2019.

2018 North Carolina Rate Case

On February 27, 2019, Piedmont filed a notice with the NCUC of its intent to file a base rate adjustment application no earlier than 30 days from the notice submittal date.

OTHER REGULATORY MATTERS

Progress Energy Merger FERC Mitigation

Since December 2014, the FERC Office of Enforcement has conducted an investigation of Duke Energy’s market power filings in its application for approval of the Progress Energy merger submitted in 2012. On June 8, 2018, the FERC issued an order approving a settlement agreement under which Duke Energy paid a penalty of $3.5 million. The FERC Office of Enforcement stated in its conclusion that Duke Energy violated FERC regulations by failing to fully and accurately describe certain specific matters in its market power filings. Duke Energy neither admitted nor denied the alleged violations.

Atlantic Coast Pipeline, LLC

On September 2, 2014, Duke Energy, Dominion Resources (Dominion), Piedmont and Southern Company Gas announced the formation of Atlantic Coast Pipeline, LLC (ACP) to build and own the proposed Atlantic Coast Pipeline (ACP pipeline), an approximately 600-mile interstate natural gas pipeline running from West Virginia to North Carolina. The ACP pipeline is designed to meet, in part, the needs identified by Duke Energy Carolinas, Duke Energy Progress and Piedmont. Dominion will be responsible for building and operating the ACP pipeline and holds a leading ownership percentage in ACP of 48 percent. Duke Energy owns a 47 percent interest, which is accounted for as an equity method investment through its Gas Utilities and Infrastructure segment. Southern Company Gas maintains a 5 percent interest. See Notes 12 and 17 for additional information related to Duke Energy's ownership interest. Duke Energy Carolinas, Duke Energy Progress and Piedmont, among others, will be customers of the pipeline. Purchases will be made under several 20-year supply contracts, subject to state regulatory approval.

In 2018, the FERC issued a series of Notices to Proceed, which authorized the project to begin certain construction-related activities along the pipeline route, including supply header and compressors. On May 11, 2018, and October 19, 2018, FERC issued Notices to Proceed allowing full construction activities in all areas of West Virginia except in the Monongahela National Forest. On July 24, 2018, FERC issued a Notice to Proceed allowing full construction activities along the project route in North Carolina. On October 19, 2018, the conditions to effectiveness of the Virginia 401 water quality certification were satisfied. Immediately following receipt of the Virginia 401 certification, ACP filed a request for FERC to issue a Notice to Proceed with full construction activities in Virginia. We appreciate the professional and collaborative process by the permitting agencies designed to ensure that this critical energy infrastructure project will meet the stringent environmental standards required by law and regulation.

ACP is the subject of challenges in state and federal courts and agencies, including, among others, challenges of the project’s incidental take statement (ITS), crossings of the Blue Ridge Parkway, the Appalachian Trail, and the Monongahela and George Washington National Forests, the project’s U.S. Army Corps of Engineers (USACE) 404 permit, the Virginia conditional 401 water quality certification, the FERC Environmental Impact Statement order and the FERC order approving the Certificate of Public Convenience and Necessity. Each of these challenges alleges non-compliance on the part of federal and state permitting authorities and adverse ecological consequences if the project is permitted to proceed. ACP is vigorously defending these challenges and coordinating with the federal and state authorities which are the direct parties to the challenges. Since July 2018, notable developments in these challenges include a stay issued by the U.S. Court of Appeals for the Fourth Circuit (Fourth Circuit) on construction activities through the Monongahela and George Washington National Forests, a reissuance of the project’s ITS and Blue Ridge Parkway right-of-way and renewed challenges of these reissued permits, a stay issued by the Fourth Circuit of the project's biological opinion and ITS (which stay has halted most project construction activity), a Fourth Circuit decision vacating the project's permits to cross the Monongahela and George Washington National Forests and the Appalachian Trail and the Fourth Circuit's remand to USACE of ACP's Huntington District 404 verification.

The delays resulting from the legal challenges described above have impacted the cost and schedule for the project. As a result, project cost estimates have increased to $7.0 billion to $7.8 billion, excluding financing costs. ACP expects to achieve a late 2020 in-service date for key segments of the project, while it expects the remainder to extend into 2021. Abnormal weather, work delays (including delays due to judicial or regulatory action) and other conditions may result in cost or schedule modifications in the future.

Sabal Trail Transmission, LLC

On May 4, 2015, Duke Energy acquired a 7.5 percent ownership interest in Sabal Trail, which is accounted for as an equity method investment, from Spectra Energy Partners, LP, a master limited partnership, formed by Enbridge Inc. (formerly Spectra Energy Corp.). Spectra Energy Partners, LP holds a 50 percent ownership interest in Sabal Trail and NextEra Energy has a 42.5 percent ownership interest. Sabal Trail is a joint venture to construct a 515-mile natural gas pipeline (Sabal Trail pipeline) to transport natural gas to Florida. Total estimated project costs are approximately $3.2 billion. The Sabal Trail pipeline traverses Alabama, Georgia and Florida. The primary customers of the Sabal Trail pipeline, Duke Energy Florida and FP&L have each contracted to buy pipeline capacity for 25-year initial terms. See Notes 12 and 17 for additional information related to Duke Energy's ownership interest.

On February 3, 2016, the FERC issued an order granting the request for a CPCN to construct and operate the pipeline. The Sabal Trail pipeline received other required regulatory approvals and the Phase 1 mainline was placed in service in July 2017. On October 12, 2017, Sabal Trail filed a request with FERC to place in-service a lateral line to Duke Energy Florida's Citrus County CC. This request is required to support commissioning and testing activities at the facility. On March 16, 2018, FERC approved the Citrus lateral and it was placed in service.

On September 21, 2016, intervenors filed an appeal of FERC's CPCN orders to the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals). On August 22, 2017, the appeals court ruled against FERC in the case for failing to include enough information on the impact of greenhouse-gas emissions carried by the pipeline, vacated the CPCN order and remanded the case to FERC. In response to the August 2017 court decision, the FERC issued a draft Supplemental Environmental Impact Statement (SEIS) on September 27, 2017. On October 6, 2017, FERC and a group of industry intervenors, including Sabal Trail and Duke Energy Florida, filed separate petitions with the D.C. Circuit Court of Appeals requesting rehearing regarding the court's decision to vacate the CPCN order. On January 31, 2018, the D.C. Circuit Court of Appeals denied the requests for rehearing. On February 2, 2018, Sabal Trail filed a request with FERC for expedited issuance of its order on remand and reissuance of the CPCN. In the alternative, the pipeline requested that FERC issue a temporary emergency CPCN to allow for continued operations. On February 5, 2018, FERC issued the final SEIS. On February 6, 2018, FERC and the intervenors in this case each filed motions for stay with the D.C. Circuit Court to stay the court's mandate. On March 7, 2018, the D.C. Circuit Court of Appeals granted FERC and Sabal Trail’s stay request. On March 14, 2018, FERC issued its final order on remand, which recertified the project. On August 10, 2018, FERC denied requests for rehearing of the final order on remand.

Constitution Pipeline Company, LLC

Duke Energy owns a 24 percent ownership interest in Constitution, which is accounted for as an equity method investment. Constitution is a natural gas pipeline project slated to transport natural gas supplies from the Marcellus supply region in northern Pennsylvania to major northeastern markets. The pipeline will be constructed and operated by Williams Partners L.P., which has a 41 percent ownership share. The remaining interest is held by Cabot Oil and Gas Corporation and WGL Holdings, Inc. Before the permitting delays discussed below, Duke Energy's total anticipated contributions were approximately $229 million. As a result of the permitting delays and project uncertainty, total anticipated contributions by Duke Energy can no longer be reasonably estimated. Since April 2016, with the actions of the New York State Department of Environmental Conservation (NYSDEC), Constitution stopped construction and discontinued capitalization of future development costs until the project's uncertainty is resolved.

In December 2014, Constitution received approval from the FERC to construct and operate the proposed pipeline. However, on April 22, 2016, the NYSDEC denied Constitution’s application for a necessary water quality certification for the New York portion of the Constitution pipeline. Constitution filed legal actions in the U.S. Court of Appeals for the Second Circuit (U.S. Court of Appeals) challenging the legality and appropriateness of the NYSDEC’s decision and on August 18, 2017, the petition was denied in part and dismissed in part. In September 2017, Constitution filed a petition for a rehearing of portions of the decision unrelated to the water quality certification, which was denied by the U.S. Court of Appeals. In January 2018, Constitution petitioned the Supreme Court of the United States to review the U.S. Court of Appeals decision, and on April 30, 2018, the Supreme Court denied Constitution's petition. In October 2017, Constitution filed a petition for declaratory order requesting FERC to find that the NYSDEC waived its rights to issue a Section 401 water quality certification by not acting on Constitution's application within a reasonable period of time as required by statute. This petition was based on precedent established by another pipeline’s successful petition with FERC following a District of Columbia Circuit Court ruling. On January 11, 2018, FERC denied Constitution's petition. In February 2018, Constitution filed a rehearing request with FERC of its finding that the NYSDEC did not waive the Section 401 certification requirement. On July 19, 2018, FERC denied Constitution's rehearing request. Constitution is currently unable to approximate an in-service date for the project due to the NYSDEC's denial of the water quality certification. The Constitution partners remain committed to the project and are evaluating next steps to move the project forward. On June 25, 2018, Constitution filed with FERC a Request for Extension of Time until December 2, 2020, for construction of the project. On November 5, 2018, FERC issued an Order Granting Extension of Time.

See Notes 12 and 17 for additional information related to ownership interest and carrying value of the investment.

Potential Coal Plant Retirements

The Subsidiary Registrants periodically file IRPs with their state regulatory commissions. The IRPs provide a view of forecasted energy needs over a long term (10 to 20 years) and options being considered to meet those needs. IRPs filed by the Subsidiary Registrants included planning assumptions to potentially retire certain coal-fired generating facilities in North Carolina and Indiana earlier than their current estimated useful lives primarily because facilities do not have the requisite emission control equipment to meet regulatory requirements expected to apply in the near future. Duke Energy continues to evaluate the potential need to retire these coal-fired generating facilities earlier than the current estimated useful lives and plans to seek regulatory recovery for amounts that would not be otherwise recovered when any of these assets are retired.

The table below contains the net carrying value of generating facilities planned for retirement or included in recent IRPs as evaluated for potential retirement due to a lack of requisite environmental control equipment. Dollar amounts in the table below are included in Net property, plant and equipment on the Consolidated Balance Sheets as of December 31, 2018, and exclude capitalized asset retirement costs.

 

 

 

Remaining Net

 

Capacity

 

Book Value

 

(in MW)

 

(in millions)

Duke Energy Carolinas

 

 

 

Allen Steam Station Units 1-3(a)

585

 

 

$

162

 

Duke Energy Indiana

 

 

 

Gallagher Units 2 and 4(b)

280

 

 

121

 

Total Duke Energy

865

 

 

$

283

 

(a) Duke Energy Carolinas will retire Allen Steam Station Units 1 through 3 by December 31, 2024, as part of the resolution of a lawsuit involving alleged New Source Review violations.

(b) Duke Energy Indiana committed to either retire or stop burning coal at Gallagher Units 2 and 4 by December 31, 2022, as part of the 2016 settlement of Edwardsport IGCC matters.

Refer to the "Western Carolinas Modernization Plan" discussion above for details of Duke Energy Progress' planned retirements.

 

 

 

5. COMMITMENTS AND CONTINGENCIES

INSURANCE

General Insurance

The Duke Energy Registrants have insurance and reinsurance coverage either directly or through indemnification from Duke Energy’s captive insurance company, Bison, and its affiliates, consistent with companies engaged in similar commercial operations with similar type properties. The Duke Energy Registrants’ coverage includes (i) commercial general liability coverage for liabilities arising to third parties for bodily injury and property damage; (ii) workers’ compensation; (iii) automobile liability coverage; and (iv) property coverage for all real and personal property damage. Real and personal property damage coverage excludes electric transmission and distribution lines, but includes damages arising from boiler and machinery breakdowns, earthquakes, flood damage and extra expense, but not outage or replacement power coverage. All coverage is subject to certain deductibles or retentions, sublimits, exclusions, terms and conditions common for companies with similar types of operations. The Duke Energy Registrants self-insure their electric transmission and distribution lines against loss due to storm damage and other natural disasters. As discussed further in Note 4, Duke Energy Florida maintains a storm damage reserve and has a regulatory mechanism to recover the cost of named storms on an expedited basis.

The cost of the Duke Energy Registrants’ coverage can fluctuate from year to year reflecting claims history and conditions of the insurance and reinsurance markets.

In the event of a loss, terms and amounts of insurance and reinsurance available might not be adequate to cover claims and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered by other sources, could have a material effect on the Duke Energy Registrants’ results of operations, cash flows or financial position. Each company is responsible to the extent losses may be excluded or exceed limits of the coverage available.

Nuclear Insurance

Duke Energy Carolinas owns and operates McGuire and Oconee and operates and has a partial ownership interest in Catawba. McGuire and Catawba each have two reactors. Oconee has three reactors. The other joint owners of Catawba reimburse Duke Energy Carolinas for certain expenses associated with nuclear insurance per the Catawba joint owner agreements.

Duke Energy Progress owns and operates Robinson, Brunswick and Harris. Robinson and Harris each have one reactor. Brunswick has two reactors.

Duke Energy Florida owns Crystal River Unit 3, which permanently ceased operation in 2013 and reached a SAFSTOR condition in January 2018 after the successful transfer of all used nuclear fuel assemblies to an on-site dry cask storage facility.

In the event of a loss, terms and amounts of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered by other sources, could have a material effect on Duke Energy Carolinas’, Duke Energy Progress’ and Duke Energy Florida’s results of operations, cash flows or financial position. Each company is responsible to the extent losses may be excluded or exceed limits of the coverage available.

Nuclear Liability Coverage

The Price-Anderson Act requires owners of nuclear reactors to provide for public nuclear liability protection per nuclear incident up to a maximum total financial protection liability. The maximum total financial protection liability, which is approximately $14.1 billion, is subject to change every five years for inflation and for the number of licensed reactors. Total nuclear liability coverage consists of a combination of private primary nuclear liability insurance coverage and a mandatory industry risk-sharing program to provide for excess nuclear liability coverage above the maximum reasonably available private primary coverage. The U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims.

Primary Liability Insurance

Duke Energy Carolinas and Duke Energy Progress have purchased the maximum reasonably available private primary nuclear liability insurance as required by law, which is $450 million per station. Duke Energy Florida has purchased $100 million primary nuclear liability insurance in compliance with the law.

 

 

Excess Liability Program

This program provides $13.6 billion of coverage per incident through the Price-Anderson Act’s mandatory industrywide excess secondary financial protection program of risk pooling. This amount is the product of potential cumulative retrospective premium assessments of $138 million times the current 99 licensed commercial nuclear reactors in the U.S. Under this program, licensees could be assessed retrospective premiums to compensate for public nuclear liability damages in the event of a nuclear incident at any licensed facility in the U.S. Retrospective premiums may be assessed at a rate not to exceed $20.5 million per year per licensed reactor for each incident. The assessment may be subject to state premium taxes.

Nuclear Property and Accidental Outage Coverage

Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida are members of NEIL, an industry mutual insurance company, which provides property damage, nuclear accident decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. Additionally, NEIL provides accidental outage coverage for each station for losses in the event of a major accidental outage at an insured nuclear station.

Pursuant to regulations of the NRC, each company’s property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after a qualifying accident and second, to decontaminate the plant before any proceeds can be used for decommissioning, plant repair or restoration.

Losses resulting from acts of terrorism are covered as common occurrences, such that if terrorist acts occur against one or more commercial nuclear power plants insured by NEIL within a 12-month period, they would be treated as one event and the owners of the plants where the act occurred would share one full limit of liability. The full limit of liability is currently $3.2 billion. NEIL sublimits the total aggregate for all of their policies for non-nuclear terrorist events to approximately $1.8 billion.

Each nuclear facility has accident property damage, nuclear accident decontamination and premature decommissioning liability insurance from NEIL with limits of $1.5 billion, except for Crystal River Unit 3. Crystal River Unit 3’s limit is $50 million and is on an actual cash value basis. All nuclear facilities except for Catawba and Crystal River Unit 3 also share an additional $1.25 billion nuclear accident insurance limit above their dedicated underlying limit. This shared additional excess limit is not subject to reinstatement in the event of a loss. Catawba has a dedicated $1.25 billion of additional nuclear accident insurance limit above its dedicated underlying limit. Catawba and Oconee also have an additional $750 million of non-nuclear accident property damage limit. All coverages are subject to sublimits and significant deductibles.

NEIL’s Accidental Outage policy provides some coverage, such as business interruption, for losses in the event of a major accident property damage outage of a nuclear unit. Coverage is provided on a weekly limit basis after a significant waiting period deductible and at 100 percent of the available weekly limits for 52 weeks and 80 percent of the available weekly limits for the next 110 weeks. Coverage is provided until these available weekly periods are met where the accidental outage policy limit will not exceed $490 million for McGuire, Catawba and Harris, $476 million for Brunswick, $462 million for Oconee and $392 million for Robinson. NEIL sublimits the accidental outage recovery to the first 104 weeks of coverage not to exceed $328 million from non-nuclear accidental property damage. Coverage amounts decrease in the event more than one unit at a station is out of service due to a common accident. All coverages are subject to sublimits and significant deductibles.

Potential Retroactive Premium Assessments

In the event of NEIL losses, NEIL’s board of directors may assess member companies' retroactive premiums of amounts up to 10 times their annual premiums for up to six years after a loss. NEIL has never exercised this assessment. The maximum aggregate annual retrospective premium obligations for Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida are $159 million, $97 million and $1 million, respectively. Duke Energy Carolinas' maximum assessment amount includes 100 percent of potential obligations to NEIL for jointly owned reactors. Duke Energy Carolinas would seek reimbursement from the joint owners for their portion of these assessment amounts.

ENVIRONMENTAL

The Duke Energy Registrants are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These regulations can be changed from time to time, imposing new obligations on the Duke Energy Registrants. The following environmental matters impact all of the Duke Energy Registrants.

 

 

 

Remediation Activities

In addition to the ARO recorded as a result of various environmental regulations, discussed in Note 9, the Duke Energy Registrants are responsible for environmental remediation at various sites. These include certain properties that are part of ongoing operations and sites formerly owned or used by Duke Energy entities. These sites are in various stages of investigation, remediation and monitoring. Managed in conjunction with relevant federal, state and local agencies, remediation activities vary based upon site conditions and location, remediation requirements, complexity and sharing of responsibility. If remediation activities involve joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Duke Energy Registrants could potentially be held responsible for environmental impacts caused by other potentially responsible parties and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. Liabilities are recorded when losses become probable and are reasonably estimable. The total costs that may be incurred cannot be estimated because the extent of environmental impact, allocation among potentially responsible parties, remediation alternatives and/or regulatory decisions have not yet been determined at all sites. Additional costs associated with remediation activities are likely to be incurred in the future and could be significant. Costs are typically expensed as Operation, maintenance and other in the Consolidated Statements of Operations unless regulatory recovery of the costs is deemed probable.

The following tables contain information regarding reserves for probable and estimable costs related to the various environmental sites. These reserves are recorded in Accounts payable within Current Liabilities and Other within Other Noncurrent Liabilities on the Consolidated Balance Sheets.

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

Balance at December 31, 2015

$

94

 

 

$

10

 

 

$

17

 

 

$

3

 

 

$

14

 

 

$

54

 

 

$

12

 

Provisions/adjustments

19

 

 

4

 

 

7

 

 

2

 

 

4

 

 

7

 

 

1

 

Cash reductions

(15

)

 

(4

)

 

(6

)

 

(2

)

 

(4

)

 

(2

)

 

(3

)

Balance at December 31, 2016

98

 

 

10

 

 

18

 

 

3

 

 

14

 

 

59

 

 

10

 

Provisions/adjustments

8

 

 

3

 

 

3

 

 

2

 

 

2

 

 

3

 

 

(4

)

Cash reductions

(25

)

 

(3

)

 

(6

)

 

(2

)

 

(4

)

 

(15

)

 

(1

)

Balance at December 31, 2017

81

 

 

10

 

 

15

 

 

3

 

 

12

 

 

47

 

 

5

 

Provisions/adjustments

26

 

 

3

 

 

2

 

 

3

 

 

(2

)

 

21

 

 

1

 

Cash reductions

(30

)

 

(2

)

 

(6

)

 

(2

)

 

(4

)

 

(20

)

 

(1

)

Balance at December 31, 2018

$

77

 

 

$

11

 

 

$

11

 

 

$

4

 

 

$

6

 

 

$

48

 

 

$

5

 

As of December 31, 2016, and October 31, 2016 and 2015, Piedmont's environmental reserve was $1 million. As of December 31, 2018, and 2017, the reserve was $2 million.

Additional losses in excess of recorded reserves that could be incurred for the stages of investigation, remediation and monitoring for environmental sites that have been evaluated at this time are not material except as presented in the table below.

(in millions)

 

Duke Energy

$

46

 

Duke Energy Carolinas

17

 

Duke Energy Ohio

19

 

Piedmont

2

 

 

 

 

North Carolina and South Carolina Ash Basins

In February 2014, a break in a stormwater pipe beneath an ash basin at Duke Energy Carolinas’ retired Dan River Steam Station caused a release of ash basin water and ash into the Dan River. In July 2014, Duke Energy completed remediation work identified by the EPA and continues to cooperate with the EPA's civil enforcement process. The NCDEQ has historically assessed Duke Energy Carolinas and Duke Energy Progress with NOVs for violations that were most often resolved through satisfactory corrective actions and minor, if any, fines or penalties. Subsequent to the Dan River ash release, Duke Energy Carolinas and Duke Energy Progress have been served with a higher level of NOVs, including assessed penalties for violations at Sutton and Dan River Steam Station. Duke Energy Carolinas and Duke Energy Progress continue to resolve violations through corrective actions, and associated penalties related to existing unresolved NOVs are not expected to be material.

LITIGATION

Duke Energy Carolinas and Duke Energy Progress

Coal Ash Insurance Coverage Litigation

In March 2017, Duke Energy Carolinas and Duke Energy Progress filed a civil action in the North Carolina Superior Court against various insurance providers. The lawsuit seeks payment for coal ash-related liabilities covered by third-party liability insurance policies. The insurance policies were issued between 1971 and 1986 and provide third-party liability insurance for property damage. The civil action seeks damages for breach of contract and indemnification for costs arising from the Coal Ash Act and the EPA CCR rule at 15 coal-fired plants in North Carolina and South Carolina. On January 23, 2019, the court granted the parties’ joint motion for a four month stay of the proceedings, until June 3, 2019, to allow the parties to discuss potential resolution. If the case is not fully resolved at that time, litigation will resume. The trial remains scheduled for August 2020. Duke Energy Carolinas and Duke Energy Progress cannot predict the outcome of this matter.

NCDEQ State Enforcement Actions

In the first quarter of 2013, SELC sent notices of intent to sue Duke Energy Carolinas and Duke Energy Progress related to alleged CWA violations from coal ash basins at two coal-fired power plants in North Carolina. The NCDEQ filed enforcement actions against Duke Energy Carolinas and Duke Energy Progress alleging violations of water discharge permits and North Carolina groundwater standards. The cases have been consolidated and are being heard before a single judge in the North Carolina Superior Court.

On August 16, 2013, the NCDEQ filed an enforcement action against Duke Energy Carolinas and Duke Energy Progress related to the remaining coal-fired power plants in North Carolina, alleging violations of the CWA and violations of the North Carolina groundwater standards. Both of these cases have been assigned to the judge handling the enforcement actions discussed above. SELC is representing several environmental groups who have been permitted to intervene in these cases.

The court issued orders in 2016 granting Motions for Partial Summary Judgment for seven of the 14 North Carolina plants with coal ash basins named in the enforcement actions. On February 13, 2017, the court issued an order denying motions for partial summary judgment brought by both the environmental groups and Duke Energy Carolinas and Duke Energy Progress for the remaining seven plants. On March 15, 2017, Duke Energy Carolinas and Duke Energy Progress filed a Notice of Appeal with the North Carolina Court of Appeals to challenge the trial court’s order. The parties were unable to reach an agreement at mediation in April 2017 and submitted briefs to the trial court on remaining issues to be tried. On August 1, 2018, the Court of Appeals dismissed the appeal and the matter is proceeding before the trial court. No trial date has been scheduled. Duke Energy Carolinas and Duke Energy Progress cannot predict the outcome of this matter.

Federal Citizens Suits

On June 13, 2016, RRBA filed a federal citizen suit in the Middle District of North Carolina alleging unpermitted discharges to surface water and groundwater violations at the Mayo Plant. On August 19, 2016, Duke Energy Progress filed a Motion to Dismiss. On April 26, 2017, the court entered an order dismissing four of the claims in the federal citizen suit. Two claims relating to alleged violations of NPDES permit provisions survived the motion to dismiss, and Duke Energy Progress filed its response on May 10, 2017. Duke Energy Progress and RRBA each filed motions for summary judgment on March 23, 2018. The court has not yet ruled on these motions.

On May 16, 2017, RRBA filed a federal citizen suit in the U.S. District Court for the Middle District of North Carolina, which asserts two claims relating to alleged violations of NPDES permit provisions at the Roxboro Plant and one claim relating to the use of nearby water bodies. Duke Energy Progress and RRBA each filed motions for summary judgment on April 17, 2018, and the court has not yet ruled on these motions.

On May 8, 2018, on motion from Duke Energy Progress, the court ordered trial in both of the above matters to be consolidated. Trial is currently scheduled to begin July 15, 2019.

On June 20, 2017, RRBA filed a federal citizen suit in the U.S. District Court for the Middle District of North Carolina challenging the closure plans at the Mayo Plant under the EPA CCR Rule. Duke Energy Progress filed a motion to dismiss, which was granted by the court on March 30, 2018. RRBA had until April 30, 2018, to file an appeal to the Fourth Circuit but did not do so.

On August 2, 2017, RRBA filed a federal citizen suit in the U.S. District Court for the Middle District of North Carolina challenging the closure plans at the Roxboro Plant under the EPA CCR Rule. Duke Energy Progress filed a motion to dismiss on October 2, 2017, which was granted by the court on May 29, 2018. RRBA had until June 28, 2018, to file an appeal to the Fourth Circuit but did not do so.

On December 5, 2017, various parties filed a federal citizen suit in the U.S. District Court for the Middle District of North Carolina for alleged violations at Duke Energy Carolinas' Belews Creek under the CWA. Duke Energy Carolinas' answer to the complaint was filed on August 27, 2018. On October 10, 2018, Duke Energy Carolinas filed Motions to Dismiss for lack of standing, Motion for Judgment on the Pleadings and Motion to Stay Discovery. On January 9, 2019, the court entered an order denying Duke Energy Carolinas' motion to stay discovery. There has been no ruling on the other pending motions.

Duke Energy Carolinas and Duke Energy Progress cannot predict the outcome of these matters.

Groundwater Contamination Claims

Beginning in May 2015, a number of residents living in the vicinity of the North Carolina facilities with ash basins received letters from the NCDEQ advising them not to drink water from the private wells on their land tested by the NCDEQ as the samples were found to have certain substances at levels higher than the criteria set by the DHHS. Results of CSAs testing performed by Duke Energy under the Coal Ash Act have been consistent with historical data provided to state regulators over many years. The DHHS and NCDEQ sent follow-up letters on October 15, 2015, to residents near coal ash basins who have had their wells tested, stating that private well samplings at a considerable distance from coal ash basins, as well as some municipal water supplies, contain similar levels of vanadium and hexavalent chromium, which led investigators to believe these constituents are naturally occurring. In March 2016, DHHS rescinded the advisories.

Duke Energy Carolinas and Duke Energy Progress have received formal demand letters from residents near Duke Energy Carolinas' and Duke Energy Progress' coal ash basins. The residents claim damages for nuisance and diminution in property value, among other things. The parties held three days of mediation discussions, which ended at impasse. On January 6, 2017, Duke Energy Carolinas and Duke Energy Progress received the plaintiffs' notice of their intent to file suits should the matter not settle. The NCDEQ preliminarily approved Duke Energy’s permanent water solution plans on January 13, 2017, and as a result shortly thereafter, Duke Energy issued a press release, providing additional details regarding the homeowner compensation package. This package consists of three components: (i) a $5,000 goodwill payment to each eligible well owner to support the transition to a new water supply, (ii) where a public water supply is available and selected by the eligible well owner, a stipend to cover 25 years of water bills and (iii) the Property Value Protection Plan. The Property Value Protection Plan is a program offered by Duke Energy designed to guarantee eligible plant neighbors the fair market value of their residential property should they decide to sell their property during the time that the plan is offered. Payments are being made and the remaining reserves are not material.

On August 23, 2017, a class-action suit was filed in Wake County Superior Court, North Carolina, against Duke Energy Carolinas and Duke Energy Progress on behalf of certain property owners living near coal ash impoundments at Allen, Asheville, Belews Creek, Buck, Cliffside, Lee, Marshall, Mayo and Roxboro. The class is defined as those who are well-eligible under the Coal Ash Act or those to whom Duke Energy has promised a permanent replacement water supply and seeks declaratory and injunctive relief, along with compensatory damages. Plaintiffs allege that Duke Energy’s improper maintenance of coal ash impoundments caused harm, particularly through groundwater contamination. Despite NCDEQ’s preliminary approval, Plaintiffs contend that Duke Energy’s proposed permanent water solutions plan fails to comply with the Coal Ash Act. On September 28, 2017, Duke Energy Carolinas and Duke Energy Progress filed a Motion to Dismiss and Motion to Strike the class designation. The parties entered into a Settlement Agreement on January 24, 2018, which resulted in the dismissal of the underlying class action on January 25, 2018.

On September 14, 2017, a complaint was filed against Duke Energy Progress in New Hanover County Superior Court by a group of homeowners residing approximately 1 mile from Duke Energy Progress' Sutton Steam Plant. The homeowners allege that coal ash constituents have been migrating from ash impoundments at Sutton into their groundwater for decades and that in 2015, Duke Energy Progress discovered these releases of coal ash, but failed to notify any officials or neighbors and failed to take remedial action. The homeowners claim unspecified physical and mental injuries as a result of consuming their well water and seek actual damages for personal injury, medical monitoring and punitive damages. On March 6, 2018, Plaintiffs' counsel voluntarily dismissed the action without prejudice.

 

Duke Energy Carolinas

Asbestos-related Injuries and Damages Claims

Duke Energy Carolinas has experienced numerous claims for indemnification and medical cost reimbursement related to asbestos exposure. These claims relate to damages for bodily injuries alleged to have arisen from exposure to or use of asbestos in connection with construction and maintenance activities conducted on its electric generation plants prior to 1985. As of December 31, 2018, there were 164 asserted claims for non-malignant cases with the cumulative relief sought of up to $42 million and 87 asserted claims for malignant cases with the cumulative relief sought of up to $21 million. Based on Duke Energy Carolinas’ experience, it is expected that the ultimate resolution of most of these claims likely will be less than the amount claimed.

Duke Energy Carolinas has recognized asbestos-related reserves of $630 million and $489 million at December 31, 2018, and 2017, respectively. These reserves are classified in Other within Other Noncurrent Liabilities and Other within Current Liabilities on the Consolidated Balance Sheets. These reserves are based upon Duke Energy Carolinas' best estimate for current and future asbestos claims through 2038 and are recorded on an undiscounted basis. In light of the uncertainties inherent in a longer-term forecast, management does not believe they can reasonably estimate the indemnity and medical costs that might be incurred after 2038 related to such potential claims. It is possible Duke Energy Carolinas may incur asbestos liabilities in excess of the recorded reserves.

Duke Energy Carolinas has third-party insurance to cover certain losses related to asbestos-related injuries and damages above an aggregate self-insured retention. Duke Energy Carolinas’ cumulative payments began to exceed the self-insurance retention in 2008. Future payments up to the policy limit will be reimbursed by the third-party insurance carrier. The insurance policy limit for potential future insurance recoveries indemnification and medical cost claim payments is $764 million in excess of the self-insured retention. Receivables for insurance recoveries were $739 million and $585 million at December 31, 2018, and 2017, respectively. These amounts are classified in Other within Other Noncurrent Assets and Receivables within Current Assets on the Consolidated Balance Sheets. Duke Energy Carolinas is not aware of any uncertainties regarding the legal sufficiency of insurance claims. Duke Energy Carolinas believes the insurance recovery asset is probable of recovery as the insurance carrier continues to have a strong financial strength rating.

Duke Energy Progress and Duke Energy Florida

Spent Nuclear Fuel Matters

On October 16, 2014, Duke Energy Progress and Duke Energy Florida sued the U.S. in the U.S. Court of Federal Claims. The lawsuit claimed the Department of Energy breached a contract in failing to accept spent nuclear fuel under the Nuclear Waste Policy Act of 1982 and asserted damages for the cost of on-site storage. Duke Energy Progress and Duke Energy Florida asserted damages for the period January 1, 2011, through December 31, 2013, of $48 million and $25 million, respectively. On November 17, 2017, the Court awarded Duke Energy Progress and Duke Energy Florida $48 million and $21 million, respectively, subject to appeal. No appeals were filed and Duke Energy Progress and Duke Energy Florida recognized the recoveries in the first quarter of 2018. Claims for all periods through 2013 have been resolved. On June 22, 2018, Duke Energy Progress and Duke Energy Florida filed a complaint for damages incurred for 2014 through first quarter 2018.

Duke Energy Progress

Gypsum Supply Agreements Matter

On June 30, 2017, CertainTeed filed a declaratory judgment action against Duke Energy Progress in the North Carolina Business Court relating to a gypsum supply agreement. In its complaint, CertainTeed sought an order from the court declaring that the minimum amount of gypsum Duke Energy Progress must provide to CertainTeed under the supply agreement was 50,000 tons per month through 2029. Trial in this matter was completed on July 16, 2018. On August 29, 2018, the court issued an order and opinion finding that Duke Energy Progress is required to supply 50,000 tons of gypsum/month, but that CertainTeed’s sole remedy for Duke Energy Progress’ long-term discontinuance under the agreement is liquidated damages. On November 14, 2018, the parties reached a settlement agreement. The amount owed under the liquidated damages provision is approximately $90 million on an undiscounted basis over 10 years. Approximately $3 million was paid in 2018. As of December 31, 2018, $9 million is recorded in Accounts payable within Current Liabilities and $63 million in Other within Other Noncurrent Liabilities on the Consolidated Balance Sheets. The liability is recorded on a discounted basis at a rate of approximately 4 percent. These costs are probable of recovery from customers and are recorded in Regulatory Assets within Other Noncurrent Assets on the Consolidated Balance Sheets.

 

 

 

Duke Energy Florida

Fluor Contract Litigation

On January 29, 2019, Fluor filed a breach of contract lawsuit in the U.S. District Court for the Middle District of Florida against Duke Energy Florida related to an EPC agreement for the combined-cycle natural gas plant in Citrus County, Florida. Fluor filed an amended complaint on February, 13, 2019. Fluor’s multicount complaint seeks civil, statutory and contractual remedies related to Duke Energy Florida’s $67 million draw in early 2019, on Fluor’s letter of credit and offset of invoiced amounts. Duke Energy Florida is attempting to recover from Fluor $110 million in additional costs incurred by Duke Energy Florida. Duke Energy Florida cannot predict the outcome of this matter. See Note 4 for additional information.

Class-Action Lawsuit

On February 22, 2016, a lawsuit was filed in the U.S. District Court for the Southern District of Florida on behalf of a class of Duke Energy Florida and FP&L’s customers in Florida. The suit alleges the State of Florida’s NCRS are unconstitutional and pre-empted by federal law. Plaintiffs claim they are entitled to repayment of all money paid by customers of Duke Energy Florida and FP&L as a result of the NCRS, as well as an injunction against any future charges under those statutes. The constitutionality of the NCRS has been challenged unsuccessfully in a number of prior cases on alternative grounds. Duke Energy Florida and FP&L filed motions to dismiss the complaint on May 5, 2016. On September 21, 2016, the Court granted the motions to dismiss with prejudice. Plaintiffs filed a motion for reconsideration, which was denied. On January 4, 2017, plaintiffs filed a notice of appeal to the Eleventh Circuit U.S. Court of Appeals (Eleventh Circuit). On July 11, 2018, the Eleventh Circuit affirmed the U.S. District Court's dismissal of the lawsuit. The deadline to file a petition for cert was October 9, 2018, and no petition was filed; therefore, the dismissal of the lawsuit is final.

Westinghouse Contract Litigation

On March 28, 2014, Duke Energy Florida filed a lawsuit against Westinghouse in the U.S. District Court for the Western District of North Carolina. The lawsuit seeks recovery of $54 million in milestone payments in excess of work performed under an EPC for Levy as well as a determination by the court of the amounts due to Westinghouse as a result of the termination of an EPC contract. Duke Energy Florida recognized an exit obligation as a result of the termination of the EPC. On March 31, 2014, Westinghouse filed a separate lawsuit against Duke Energy Florida in U.S. District Court for the Western District of Pennsylvania alleging damages under the same EPC contract in excess of $510 million for engineering and design work, costs to end supplier contracts and an alleged termination fee. On June 9, 2014, the judge in the North Carolina case ruled that the litigation will proceed in the Western District of North Carolina.

On July 11, 2016, Duke Energy Florida and Westinghouse filed separate Motions for Summary Judgment. On September 29, 2016, the court issued its ruling, granting Westinghouse a $30 million termination fee claim and dismissing Duke Energy Florida's $54 million refund claim. Westinghouse's claim for termination costs continued to trial. Following a trial on the matter, the court issued an order in December 2016 denying Westinghouse’s claim for termination costs and reaffirming its earlier ruling in favor of Westinghouse on the $30 million termination fee. Judgment was entered against Duke Energy Florida in the amount of approximately $34 million, which includes prejudgment interest. Westinghouse appealed the trial court's order to the Fourth Circuit and Duke Energy Florida cross-appealed.

On March 29, 2017, Westinghouse filed Chapter 11 bankruptcy in the Southern District of New York, which automatically stayed the appeal. On May 23, 2017, the bankruptcy court entered an order lifting the stay with respect to the appeal. Westinghouse and Duke Energy Florida executed a settlement agreement resolving this matter on April 5, 2018. The bankruptcy court approved the settlement and Duke Energy Florida paid approximately $34 million to Westinghouse in July 2018 pursuant to this agreement. At the request of the parties, the Fourth Circuit has dismissed the appeal.

MGP Cost Recovery Action

On December 30, 2011, Duke Energy Florida filed a lawsuit against FirstEnergy to recover investigation and remediation costs incurred by Duke Energy Florida in connection with the restoration of two former MGP sites in Florida. Duke Energy Florida alleged that FirstEnergy, as the successor to Associated Gas & Electric Co., owes past and future contribution and response costs of up to $43 million for the investigation and remediation of MGP sites. On December 6, 2016, the trial court entered judgment against Duke Energy Florida in the case. In January 2017, Duke Energy Florida appealed the decision to the U.S. Court of Appeals for the Sixth Circuit, which affirmed the trial court's ruling on April 10, 2018. The dismissal of the lawsuit is therefore final.

Other Litigation and Legal Proceedings

The Duke Energy Registrants are involved in other legal, tax and regulatory proceedings arising in the ordinary course of business, some of which involve significant amounts. The Duke Energy Registrants believe the final disposition of these proceedings will not have a material effect on their results of operations, cash flows or financial position.

The table below presents recorded reserves based on management’s best estimate of probable loss for legal matters, excluding asbestos-related reserves, the CertainTeed liquidated damages obligation and the exit obligation in 2017 related to the termination of an EPC contract. Reserves are classified on the Consolidated Balance Sheets in Other within Other Noncurrent Liabilities and Other within Current Liabilities. The reasonably possible range of loss in excess of recorded reserves is not material, other than as described above.

 

December 31,

(in millions)

2018

 

2017

Reserves for Legal Matters

 

 

 

Duke Energy

$

65

 

 

$

88

 

Duke Energy Carolinas

9

 

 

30

 

Progress Energy

54

 

 

55

 

Duke Energy Progress

12

 

 

13

 

Duke Energy Florida

24

 

 

24

 

Piedmont

1

 

 

2

 

OTHER COMMITMENTS AND CONTINGENCIES

General

As part of their normal business, the Duke Energy Registrants are party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. These guarantees involve elements of performance and credit risk, which are not fully recognized on the Consolidated Balance Sheets and have unlimited maximum potential payments. However, the Duke Energy Registrants do not believe these guarantees will have a material effect on their results of operations, cash flows or financial position.

Purchase Obligations

Purchased Power

Duke Energy Progress, Duke Energy Florida and Duke Energy Ohio have ongoing purchased power contracts, including renewable energy contracts, with other utilities, wholesale marketers, co-generators and qualified facilities. These purchased power contracts generally provide for capacity and energy payments. In addition, Duke Energy Progress and Duke Energy Florida have various contracts to secure transmission rights.

The following table presents executory purchased power contracts with terms exceeding one year, excluding contracts classified as leases.

 

 

 

Minimum Purchase Amount at December 31, 2018

 

Contract

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in millions)

Expiration

 

2019

 

2020

 

2021

 

2022

 

2023

 

Thereafter

 

Total

Duke Energy Progress(a)

2022-2031

 

$

51

 

 

$

52

 

 

$

53

 

 

$

30

 

 

$

25

 

 

$

215

 

 

$

426

 

Duke Energy Florida(b)

2021-2025

 

363

 

 

380

 

 

365

 

 

363

 

 

382

 

 

361

 

 

2,214

 

Duke Energy Ohio(c)(d)

2020-2022

 

146

 

 

117

 

 

53

 

 

11

 

 

 

 

 

 

327

 

(a) Contracts represent 100 percent of net plant output.

(b) Contracts represent between 81 percent and 100 percent of net plant output.

(c) Contracts represent between 1 percent and 8 percent of net plant output.

(d) Excludes PPA with OVEC. See Note 17 for additional information.

 

 

 

Gas Supply and Capacity Contracts

Duke Energy Ohio and Piedmont routinely enter into long-term natural gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services needed in their businesses. These commitments include pipeline and storage capacity contracts and natural gas supply contracts to provide service to customers. Costs arising from the natural gas supply commodity and capacity commitments, while significant, are pass-through costs to customers and are generally fully recoverable through the fuel adjustment or PGA procedures and prudence reviews in North Carolina and South Carolina and under the Tennessee Incentive Plan in Tennessee. In the Midwest, these costs are recovered via the Gas Cost Recovery Rate in Ohio or the Gas Cost Adjustment Clause in Kentucky. The time periods for fixed payments under pipeline and storage capacity contracts are up to 16 years. The time periods for fixed payments under natural gas supply contracts are up to seven years. The time period for the natural gas supply purchase commitments is up to 12 years.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the FERC in order to maintain rights to access the natural gas storage or pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the Consolidated Statements of Operations and Comprehensive Income as part of natural gas purchases and are included in Cost of natural gas.

The following table presents future unconditional purchase obligations under natural gas supply and capacity contracts as of December 31, 2018.

(in millions)

Duke Energy

Duke Energy Ohio

Piedmont

2019

$

314

 

$

38

 

$

276

 

2020

287

 

30

 

257

 

2021

255

 

29

 

226

 

2022

225

 

11

 

214

 

2023

148

 

4

 

144

 

Thereafter

1,067

 

 

1,067

 

Total

$

2,296

 

$

112

 

$

2,184

 

 

Operating and Capital Lease Commitments

The Duke Energy Registrants lease office buildings, railcars, vehicles and other property and equipment with various terms and expiration dates. Additionally, Duke Energy Carolinas and Duke Energy Progress have capital leases related to firm natural gas pipeline transportation capacity. Duke Energy Progress and Duke Energy Florida have entered into certain purchased power agreements, which are classified as leases. Consolidated capitalized lease obligations are classified as Long-Term Debt or Other within Current Liabilities on the Consolidated Balance Sheets. Amortization of assets recorded under capital leases is included in Depreciation and amortization and Fuel used in electric generation and purchased power on the Consolidated Statements of Operations.

 

 

 

 

 

 

 

 

 

 

 

The following tables present rental expense for operating leases. These amounts are included in Operation, maintenance and other and Fuel used in electric generation and purchased power on the Consolidated Statements of Operations.

 

Years Ended December 31,

(in millions)

2018

 

2017

 

2016

Duke Energy

$

268

 

 

$

241

 

 

$

242

 

Duke Energy Carolinas

49

 

 

44

 

 

45

 

Progress Energy

143

 

 

130

 

 

140

 

Duke Energy Progress

75

 

 

75

 

 

68

 

Duke Energy Florida

68

 

 

55

 

 

72

 

Duke Energy Ohio

13

 

 

15

 

 

16

 

Duke Energy Indiana

21

 

 

23

 

 

23

 

 

 

Years Ended December 31,

Two Months Ended December 31,

 

Year Ended October 31,

(in millions)

2018

 

2017

2016

 

2016

Piedmont

$

11

 

 

$

7

 

$

1

 

 

$

5

 

The following table presents future minimum lease payments under operating leases, which at inception had a non-cancelable term of more than one year.

 

December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

Piedmont

2019

$

239

 

 

$

33

 

 

$

97

 

 

$

49

 

 

$

48

 

 

$

2

 

 

$

6

 

$

5

 

2020

219

 

 

29

 

 

90

 

 

46

 

 

44

 

 

2

 

 

5

 

5

 

2021

186

 

 

19

 

 

79

 

 

37

 

 

42

 

 

2

 

 

4

 

5

 

2022

170

 

 

19

 

 

76

 

 

34

 

 

42

 

 

2

 

 

4

 

5

 

2023

160

 

 

17

 

 

77

 

 

35

 

 

42

 

 

2

 

 

5

 

6

Thereafter

1,017

 

 

68

 

 

455

 

 

314

 

 

141

 

 

23

 

 

66

 

11

 

Total

$

1,991

 

 

$

185

 

 

$

874

 

 

$

515

 

 

$

359

 

 

$

33

 

 

$

90

 

$

37

 

 

 

 

 

 

 

 

The following table presents future minimum lease payments under capital leases.

 

December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

2019

$

170

 

 

$

20

 

 

$

45

 

 

$

20

 

 

$

25

 

 

$

2

 

 

$

1

 

2020

174

 

 

20

 

 

46

 

 

21

 

 

25

 

 

 

 

1

 

2021

177

 

 

15

 

 

45

 

 

20

 

 

25

 

 

 

 

1

 

2022

165

 

 

15

 

 

45

 

 

21

 

 

24

 

 

 

 

1

 

2023

165

 

 

15

 

 

45

 

 

21

 

 

24

 

 

 

 

1

 

Thereafter

577

 

 

204

 

 

230

 

 

209

 

 

21

 

 

 

 

27

 

Minimum annual payments

1,428

 

 

289

 

 

456

 

 

312

 

 

144

 

 

2

 

 

32

 

Less: amount representing interest

(487

)

 

(180

)

 

(205

)

 

(175

)

 

(30

)

 

 

 

(22

)

Total

$

941

 

 

$

109

 

 

$

251

 

 

$

137

 

 

$

114

 

 

$

2

 

 

$

10

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6. DEBT AND CREDIT FACILITIES

Summary of Debt and Related Terms

The following tables summarize outstanding debt.

 

December 31, 2018

 

Weighted

 

 

 

 

 

 

 

 

 

 

Average

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Interest

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Rate

 

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Unsecured debt, maturing 2019-2078

4.26

%

 

$

20,955

 

$

1,150

 

$

3,800

 

$

50

 

$

350

 

$

1,000

 

$

408

 

$

2,150

 

Secured debt, maturing 2020-2037

3.69

%

 

4,297

 

450

 

1,703

 

300

 

1,403

 

 

 

 

First mortgage bonds, maturing 2019-2048(a)

4.32

%

 

25,628

 

8,759

 

13,100

 

7,574

 

5,526

 

1,099

 

2,670

 

 

Capital leases, maturing 2019-2051(b)

5.06

%

 

941

 

109

 

251

 

137

 

114

 

2

 

10

 

 

Tax-exempt bonds, maturing 2019-2041(c)

3.40

%

 

941

 

243

 

48

 

48

 

 

77

 

572

 

 

Notes payable and commercial paper(d)

2.73

%

 

4,035

 

 

 

 

 

 

 

 

Money pool/intercompany borrowings

 

 

 

739

 

1,385

 

444

 

108

 

299

 

317

 

198

 

Fair value hedge carrying value adjustment

 

 

5

 

5

 

 

 

 

 

 

Unamortized debt discount and premium, net(e)

 

 

1,434

 

(23

)

(29

)

(15

)

(11

)

(31

)

(8

)

(1

)

Unamortized debt issuance costs(f)

 

 

(297

)

(54

)

(112

)

(40

)

(61

)

(7

)

(20

)

(11

)

Total debt

4.13

%

 

$

57,939

 

$

11,378

 

$

20,146

 

$

8,498

 

$

7,429

 

$

2,439

 

$

3,949

 

$

2,336

 

Short-term notes payable and commercial paper

 

 

(3,410

)

 

 

 

 

 

 

 

Short-term money pool/intercompany borrowings

 

 

 

(439

)

(1,235

)

(294

)

(108

)

(274

)

(167

)

(198

)

Current maturities of long-term debt(g)

 

 

(3,406

)

(6

)

(1,672

)

(603

)

(270

)

(551

)

(63

)

(350

)

Total long-term debt(g)

 

 

$

51,123

 

$

10,933

 

$

17,239

 

$

7,601

 

$

7,051

 

$

1,614

 

$

3,719

 

$

1,788

 

 

(a) Substantially all electric utility property is mortgaged under mortgage bond indentures.

(b) Duke Energy includes $63 million and $531 million of capital lease purchase accounting adjustments related to Duke Energy Progress and Duke Energy Florida, respectively, related to power purchase agreements that are not accounted for as capital leases in their respective financial statements because of grandfathering provisions in GAAP.

(c) Substantially all tax-exempt bonds are secured by first mortgage bonds, letters of credit or the Master Credit Facility.

(d) Includes $625 million that was classified as Long-Term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities that backstop these commercial paper balances, along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted average days to maturity for Duke Energy's commercial paper program was 16 days.

(e) Duke Energy includes $1,380 million and $156 million in purchase accounting adjustments related to Progress Energy and Piedmont, respectively.

(f) Duke Energy includes $41 million in purchase accounting adjustments primarily related to the merger with Progress Energy.

(g) Refer to Note 17 for additional information on amounts from consolidated VIEs.

 

 

December 31, 2017

 

Weighted

 

 

 

 

 

 

 

 

 

 

Average

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Interest

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Rate

 

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Unsecured debt, maturing 2018-2073

4.17

%

 

$

20,409

 

$

1,150

 

$

3,950

 

$

 

$

550

 

$

900

 

$

411

 

$

2,050

 

Secured debt, maturing 2018-2037

3.15

%

 

4,458

 

450

 

1,757

 

300

 

1,457

 

 

 

 

First mortgage bonds, maturing 2018-2047(a)

4.51

%

 

23,529

 

7,959

 

11,801

 

6,776

 

5,025

 

1,100

 

2,669

 

 

Capital leases, maturing 2018-2051(b)

4.55

%

 

1,000

 

61

 

269

 

139

 

129

 

5

 

11

 

 

Tax-exempt bonds, maturing 2019-2041(c)

3.23

%

 

941

 

243

 

48

 

48

 

 

77

 

572

 

 

Notes payable and commercial paper(d)

1.57

%

 

2,788

 

 

 

 

 

 

 

 

Money pool/intercompany borrowings

 

 

 

404

 

955

 

390

 

 

54

 

311

 

364

 

Fair value hedge carrying value adjustment

 

 

6

 

6

 

 

 

 

 

 

 

Unamortized debt discount and premium, net(e)

 

 

1,582

 

(19

)

(30

)

(16

)

(10

)

(33

)

(9

)

(1

)

Unamortized debt issuance costs(f)

 

 

(271

)

(47

)

(108

)

(40

)

(56

)

(7

)

(21

)

(12

)

Total debt

4.09

%

 

$

54,442

 

$

10,207

 

$

18,642

 

$

7,597

 

$

7,095

 

$

2,096

 

$

3,944

 

$

2,401

 

Short-term notes payable and commercial paper

 

 

(2,163

)

 

 

 

 

 

 

 

Short-term money pool/intercompany borrowings

 

 

 

(104

)

(805

)

(240

)

 

(29

)

(161

)

(364

)

Current maturities of long-term debt(g)

 

 

(3,244

)

(1,205

)

(771

)

(3

)

(768

)

(3

)

(3

)

(250

)

Total long-term debt(g)

 

 

$

49,035

 

$

8,898

 

$

17,066

 

$

7,354

 

$

6,327

 

$

2,064

 

$

3,780

 

$

1,787

 

(a) Substantially all electric utility property is mortgaged under mortgage bond indentures.

(b) Duke Energy includes $81 million and $603 million of capital lease purchase accounting adjustments related to Duke Energy Progress and Duke Energy Florida, respectively, related to power purchase agreements that are not accounted for as capital leases in their respective financial statements because of grandfathering provisions in GAAP.

(c) Substantially all tax-exempt bonds are secured by first mortgage bonds, letters of credit or the Master Credit Facility.

(d) Includes $625 million that was classified as Long-Term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities that backstop these commercial paper balances, along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted average days to maturity for Duke Energy's commercial paper programs was 14 days.

(e) Duke Energy includes $1,509 million and $176 million purchase accounting adjustments related to the mergers with Progress Energy and Piedmont, respectively.

(f) Duke Energy includes $47 million in purchase accounting adjustments primarily related to the merger with Progress Energy.

(g) Refer to Note 17 for additional information on amounts from consolidated VIEs.

 

 

Current Maturities of Long-Term Debt

The following table shows the significant components of Current maturities of Long-Term Debt on the Consolidated Balance Sheets. The Duke Energy Registrants currently anticipate satisfying these obligations with cash on hand and proceeds from additional borrowings.

(in millions)

Maturity Date

 

Interest Rate

 

December 31, 2018

Unsecured Debt

 

 

 

 

 

Progress Energy

March 2019

 

7.050

%

 

$

450

 

Duke Energy (Parent)

September 2019

 

5.050

%

 

500

 

Piedmont

September 2019

 

3.155

%

(b)

350

 

Duke Energy Kentucky

October 2019

 

4.65

%

 

100

 

Progress Energy

December 2019

 

4.875

%

 

350

 

First Mortgage Bonds

 

 

 

 

 

Duke Energy Progress

January 2019

 

5.300

%

 

600

 

Duke Energy Ohio

April 2019

 

5.450

%

 

450

 

Other(a)

 

 

 

 

606

 

Current maturities of long-term debt

 

 

 

 

$

3,406

 

(a) Includes capital lease obligations, amortizing debt and small bullet maturities.

(b) Debt has a floating interest rate.

Maturities and Call Options

The following table shows the annual maturities of long-term debt for the next five years and thereafter. Amounts presented exclude short-term notes payable and commercial paper and money pool borrowings for the Subsidiary Registrants.

 

December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy(a)

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

2019

$

3,408

 

 

$

6

 

 

$

1,674

 

 

$

603

 

 

$

270

 

 

552

 

 

$

63

 

 

$

350

 

2020

3,765

 

 

907

 

 

926

 

 

354

 

 

572

 

 

 

 

503

 

 

 

2021

4,803

 

 

503

 

 

2,004

 

 

904

 

 

600

 

 

50

 

 

70

 

 

160

 

2022

2,745

 

 

353

 

 

1,032

 

 

505

 

 

77

 

 

 

 

94

 

 

 

2023

3,375

 

 

1,303

 

 

535

 

 

456

 

 

79

 

 

350

 

 

153

 

 

45

 

Thereafter

35,288

 

 

7,940

 

 

12,880

 

 

5,437

 

 

5,793

 

 

1,251

 

 

2,925

 

 

1,595

 

Total long-term debt, including current maturities

$

53,384

 

 

$

11,012

 

 

$

19,051

 

 

$

8,259

 

 

$

7,391

 

 

$

2,203

 

 

$

3,808

 

 

$

2,150

 

(a) Excludes $1,578 million in purchase accounting adjustments related to the Progress Energy merger and the Piedmont acquisition.

The Duke Energy Registrants have the ability under certain debt facilities to call and repay the obligation prior to its scheduled maturity. Therefore, the actual timing of future cash repayments could be materially different than as presented above.

 

Short-Term Obligations Classified as Long-Term Debt

Tax-exempt bonds that may be put to the Duke Energy Registrants at the option of the holder and certain commercial paper issuances and money pool borrowings are classified as Long-Term Debt on the Consolidated Balance Sheets. These tax-exempt bonds, commercial paper issuances and money pool borrowings, which are short-term obligations by nature, are classified as long term due to Duke Energy’s intent and ability to utilize such borrowings as long-term financing. As Duke Energy’s Master Credit Facility and other bilateral letter of credit agreements have non-cancelable terms in excess of one year as of the balance sheet date, Duke Energy has the ability to refinance these short-term obligations on a long-term basis. The following tables show short-term obligations classified as long-term debt.

 

December 31, 2018

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

Duke

 

Energy

 

Energy

 

Energy

 

Energy

(in millions)

Energy

 

Carolinas

 

Progress

 

Ohio

 

Indiana

Tax-exempt bonds

$

312

 

 

$

 

 

$

 

 

$

27

 

 

$

285

 

Commercial paper(a)

625

 

 

300

 

 

150

 

 

25

 

 

150

 

Total

$

937

 

 

$

300

 

 

$

150

 

 

$

52

 

 

$

435

 

 

 

December 31, 2017

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

Duke

 

Energy

 

Energy

 

Energy

 

Energy

(in millions)

Energy

 

Carolinas

 

Progress

 

Ohio

 

Indiana

Tax-exempt bonds

$

312

 

 

$

 

 

$

 

 

$

27

 

 

$

285

 

Commercial paper(a)

625

 

 

300

 

 

150

 

 

25

 

 

150

 

Total

$

937

 

 

$

300

 

 

$

150

 

 

$

52

 

 

$

435

 

(a) Progress Energy amounts are equal to Duke Energy Progress amounts.

 

 

 

 

 

 

 

 

 

 

 

 

 

Summary of Significant Debt Issuances

In January 2019, Duke Energy Ohio issued $800 million of first mortgage bonds. The issuance was split between a $400 million, 10-year tranche at 3.65 percent and a $400 million, 30-year tranche at 4.30 percent. The net proceeds will be used to refinance $450 million of Duke Energy Ohio bonds maturing in April 2019, to pay down short-term debt and for general corporate purposes.

The following tables summarize significant debt issuances (in millions).

 

 

 

 

 

Year Ended December 31, 2018

 

 

 

 

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

Maturity

 

Interest

 

Duke

 

Energy

 

Energy

 

Energy

 

Energy

Issuance Date

Date

 

Rate

 

Energy

 

(Parent)

 

Carolinas

 

Progress

 

Florida

Unsecured Debt

 

 

 

 

 

 

 

 

 

 

 

 

 

March 2018(a)

April 2025

 

3.950

%

 

$

250

 

 

$

250

 

 

$

 

 

$

 

 

$

 

May 2018(b)

May 2021

 

3.114

%

 

500

 

 

500

 

 

 

 

 

 

 

September 2018(c)

September 2078

 

5.625

%

 

500

 

 

500

 

 

 

 

 

 

 

First Mortgage Bonds

 

 

 

 

 

 

 

 

 

 

 

 

 

March 2018(d)

March 2023

 

3.050

%

 

500

 

 

 

 

500

 

 

 

 

 

March 2018(d)

March 2048

 

3.950

%

 

500

 

 

 

 

500

 

 

 

 

 

June 2018(e)

July 2028

 

3.800

%

 

600

 

 

 

 

 

 

 

 

600

June 2018(e)

July 2048

 

4.200

%

 

400

 

 

 

 

 

 

 

 

400

 

August 2018(f)

September 2023

 

3.375

%

 

300

 

 

 

 

 

 

300

 

 

 

August 2018(f)

September 2028

 

3.700

%

 

500

 

 

 

 

 

 

500

 

 

 

November 2018(g)

May 2022

 

3.350

%

 

350

 

 

 

 

350

 

 

 

 

 

November 2018(g)

November 2028

 

3.950

%

 

650

 

 

 

 

650

 

 

 

 

 

Total issuances

 

 

 

 

$

5,050

 

 

$

1,250

 

 

$

2,000

 

 

$

800

 

 

$

1,000

 

(a) Debt issued to pay down short-term debt.

  1. Debt issued to pay down short-term debt. Debt issuance has a floating debt rate.

  2. Callable after September 2023 at par. Junior subordinated hybrid debt issued to pay down short-term debt and for general corporate

purposes.

(d) Debt issued to repay at maturity a $300 million first mortgage bond due April 2018, pay down intercompany short-term debt and for general corporate purposes.

(e) Debt issued to repay a portion of intercompany short-term debt under the money pool borrowing arrangement and for general corporate purposes.

(f) Debt issued to repay short-term debt and for general corporate purposes.

(g) Debt issued to fund eligible green energy projects, including zero-carbon solar and energy storage, in the Carolinas.

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2017

 

 

 

 

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

Duke

 

Maturity

 

Interest

 

Duke

 

Energy

 

Energy

 

Energy

 

Energy

 

Energy

Issuance Date

Date

 

Rate

 

Energy

 

(Parent)

 

Carolinas

 

Progress

 

Florida

 

Ohio

Unsecured Debt

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

April 2017(a)

April 2025

 

3.364

%

 

$

420

 

 

$

420

 

 

$

 

 

$

 

 

$

 

 

$

 

June 2017(b)

June 2020

 

2.100

%

 

330

 

 

330

 

 

 

 

 

 

 

 

 

August 2017(c)

August 2022

 

2.400

%

 

500

 

 

500

 

 

 

 

 

 

 

 

 

August 2017(c)

August 2027

 

3.150

%

 

750

 

 

750

 

 

 

 

 

 

 

 

 

August 2017(c)

August 2047

 

3.950

%

 

500

 

 

500

 

 

 

 

 

 

 

 

 

December 2017(d)

December 2019

(k)

2.100

%

 

400

 

 

 

 

 

 

 

 

400

 

 

 

Secured Debt

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

February 2017(e)

June 2034

 

4.120

%

 

587

 

 

 

 

 

 

 

 

 

 

 

August 2017(f)

December 2036

 

4.110

%

 

233

 

 

 

 

 

 

 

 

 

 

 

First Mortgage Bonds

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 2017(g)

January 2020

 

1.850

%

 

250

 

 

 

 

 

 

 

 

250

 

 

 

January 2017(g)

January 2027

 

3.200

%

 

650

 

 

 

 

 

 

 

 

650

 

 

 

March 2017(h)

June 2046

 

3.700

%

 

100

 

 

 

 

 

 

 

 

 

 

100

September 2017(i)

September 2020

 

1.500

%

(l)

300

 

 

 

 

 

 

300

 

 

 

 

 

September 2017(i)

September 2047

 

3.600

%

 

500

 

 

 

 

 

 

500

 

 

 

 

 

November 2017(j)

December 2047

 

3.700

%

 

550

 

 

 

 

550

 

 

 

 

 

 

 

Total issuances

 

 

 

 

$

6,070

 

 

$

2,500

 

 

$

550

 

 

$

800

 

 

$

1,300

 

 

$

100

 

  1. Proceeds were used to refinance $400 million of unsecured debt at maturity and to repay a portion of outstanding commercial paper.

  2. Debt issued to repay a portion of outstanding commercial paper.

  3. Debt issued to repay at maturity $700 million of unsecured debt, to repay outstanding commercial paper and for general corporate purposes.

  4. Debt issued to fund storm restoration costs related to Hurricane Irma and for general corporate purposes.

(e) Portfolio financing of four Texas and Oklahoma wind facilities. Duke Energy pledged substantially all of the assets of these wind facilities and is nonrecourse to Duke Energy. Proceeds were used to reimburse Duke Energy for a portion of previously funded construction expenditures.

(f) Portfolio financing of eight solar facilities located in California, Colorado and New Mexico. Duke Energy pledged substantially all of the assets of these solar facilities and is nonrecourse to Duke Energy. Proceeds were used to reimburse Duke Energy for a portion of previously funded construction expenditures.

(g) Debt issued to fund capital expenditures for ongoing construction and capital maintenance, to repay a $250 million aggregate principal amount of bonds at maturity and for general corporate purposes.

(h) Proceeds were used to fund capital expenditures for ongoing construction, capital maintenance and for general corporate purposes.

(i) Debt issued to repay at maturity a $200 million aggregate principal amount of bonds at maturity, pay down intercompany short-term debt and for general corporate purposes, including capital expenditures.

(j) Debt issued to refinance $400 million aggregate principal amount of bonds due January 2018, pay down intercompany short-term debt and for general corporate purposes.

(k) Principal balance will be repaid in equal quarterly installments beginning in March 2018.

(l) Debt issuance has a floating interest rate.

 

Available Credit Facilities

In January 2018, Duke Energy extended the termination date of substantially all of its existing $8 billion Master Credit Facility capacity from March 16, 2022, to March 16, 2023. In May 2018, Duke Energy completed the extension process with 100 percent of all commitments to the Master Credit Facility extending to March 16, 2023. The Duke Energy Registrants, excluding Progress Energy (Parent), have borrowing capacity under the Master Credit Facility up to specified sublimits for each borrower. Duke Energy has the unilateral ability at any time to increase or decrease the borrowing sublimits of each borrower, subject to a maximum sublimit for each borrower. The amount available under the Master Credit Facility has been reduced to backstop issuances of commercial paper, certain letters of credit and variable-rate demand tax-exempt bonds that may be put to the Duke Energy Registrants at the option of the holder. Duke Energy Carolinas and Duke Energy Progress are also required to each maintain $250 million of available capacity under the Master Credit Facility as security to meet obligations under plea agreements reached with the U.S. Department of Justice in 2015 related to violations at North Carolina facilities with ash basins.

The table below includes the current borrowing sublimits and available capacity under these credit facilities.

 

December 31, 2018

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Energy

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

(Parent)

 

Carolinas

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Facility size(a)

$

8,000

 

 

$

2,650

 

 

$

1,750

 

 

$

1,400

 

 

$

650

 

 

$

450

 

 

$

600

 

 

$

500

 

Reduction to backstop issuances

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commercial paper(b)

(3,022

)

 

(917

)

 

(739

)

 

(444

)

 

(108

)

 

(299

)

 

(317

)

 

(198

)

Outstanding letters of credit

(53

)

 

(45

)

 

(4

)

 

(2

)

 

 

 

 

 

 

 

(2

)

Tax-exempt bonds

(81

)

 

 

 

 

 

 

 

 

 

 

 

(81

)

 

 

Coal ash set-aside

(500

)

 

 

 

(250

)

 

(250

)

 

 

 

 

 

 

 

 

Available capacity

$

4,344

 

 

$

1,688

 

 

$

757

 

 

$

704

 

 

$

542

 

 

$

151

 

 

$

202

 

 

$

300

 

(a) Represents the sublimit of each borrower.

(b) Duke Energy issued $625 million of commercial paper and loaned the proceeds through the money pool to Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio and Duke Energy Indiana. The balances are classified as Long-Term Debt Payable to Affiliated Companies in the Consolidated Balance Sheets.

Three-Year Revolving Credit Facility

Duke Energy (Parent) has a $1.0 billion revolving credit facility through June 2020. Borrowings under this facility will be used for general corporate purposes. As of December 31, 2018, $500 million has been drawn under the Three Year Revolver. This balance is classified as Long-term debt on Duke Energy's Consolidated Balance Sheets. Any undrawn commitments can be drawn, and borrowings can be prepaid, at any time throughout the term of the facility. The terms and conditions of the Three Year Revolver are generally consistent with those governing Duke Energy's Master Credit Facility.

Duke Energy Progress Term Loan Facility

In December 2018, Duke Energy Progress entered into a two-year term loan facility with commitments totaling $700 million. Borrowings under the facility will be used to pay storm-related costs, pay down commercial paper and to partially finance an upcoming bond maturity. As of December 31, 2018, $50 million has been drawn under the term loan. The balance is classified as Long-term debt on Duke Energy Progress' Consolidated Balance Sheets. In January and February 2019, the remaining $650 million was drawn under the term loan.

Piedmont Term Loan Facility

In September 2018, Piedmont executed an amendment to its existing senior unsecured term loan facility. The amendment increased commitments from $250 million to $350 million and extended the maturity date to September 2019. Borrowings under the facility will be used for general corporate purposes. As of December 31, 2018, the entire $350 million has been drawn under the Piedmont Term Loan. This balance is classified as Current maturities of long-term debt on Piedmont's Consolidated Balance Sheets. The terms and conditions of the Piedmont Term Loan are generally consistent with those governing Duke Energy's Master Credit Facility.

Other Debt Matters

In September 2016, Duke Energy filed a Form S-3 with the SEC. Under this Form S-3, which is uncapped, the Duke Energy Registrants, excluding Progress Energy, may issue debt and other securities in the future at amounts, prices and with terms to be determined at the time of future offerings. The registration statement was filed to replace a similar prior filing upon expiration of its three-year term and also allows for the issuance of common stock by Duke Energy.

Duke Energy has an effective Form S-3 with the SEC to sell up to $3 billion of variable denomination floating-rate demand notes, called PremierNotes. The Form S-3 states that no more than $1.5 billion of the notes will be outstanding at any particular time. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Duke Energy PremierNotes Committee, or its designee, on a weekly basis. The interest rate payable on notes held by an investor may vary based on the principal amount of the investment. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Duke Energy or at the investor’s option at any time. The balance as of December 31, 2018, and 2017 was $1,010 million and $986 million, respectively. The notes are short-term debt obligations of Duke Energy and are reflected as Notes payable and commercial paper on Duke Energy’s Consolidated Balance Sheets.

In January 2017, Duke Energy amended its Form S-3 to add Piedmont as a registrant and included in the amendment a prospectus for Piedmont under which it may issue debt securities in the same manner as other Duke Energy Registrants.

Money Pool

The Subsidiary Registrants, excluding Progress Energy (Parent), are eligible to receive support for their short-term borrowing needs through participation with Duke Energy and certain of its subsidiaries in a money pool arrangement. Under this arrangement, those companies with short-term funds may provide short-term loans to affiliates participating in this arrangement. The money pool is structured such that the Subsidiary Registrants, excluding Progress Energy (Parent), separately manage their cash needs and working capital requirements. Accordingly, there is no net settlement of receivables and payables between money pool participants. Duke Energy (Parent), may loan funds to its participating subsidiaries, but may not borrow funds through the money pool. Accordingly, as the money pool activity is between Duke Energy and its wholly owned subsidiaries, all money pool balances are eliminated within Duke Energy’s Consolidated Balance Sheets.

Money pool receivable balances are reflected within Notes receivable from affiliated companies on the Subsidiary Registrants’ Consolidated Balance Sheets. Money pool payable balances are reflected within either Notes payable to affiliated companies or Long-Term Debt Payable to Affiliated Companies on the Subsidiary Registrants’ Consolidated Balance Sheets.

Restrictive Debt Covenants

The Duke Energy Registrants’ debt and credit agreements contain various financial and other covenants. Duke Energy's Master Credit Facility contains a covenant requiring the debt-to-total capitalization ratio not to exceed 65 percent for each borrower, excluding Piedmont, and 70 percent for Piedmont. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2018, each of the Duke Energy Registrants was in compliance with all covenants related to their debt agreements. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

Other Loans

As of December 31, 2018, and 2017, Duke Energy had loans outstanding of $741 million, including $37 million at Duke Energy Progress and $701 million, including $38 million at Duke Energy Progress, respectively, against the cash surrender value of life insurance policies it owns on the lives of its executives. The amounts outstanding were carried as a reduction of the related cash surrender value that is included in Other within Other Noncurrent Assets on the Consolidated Balance Sheets.

 

7. GUARANTEES AND INDEMNIFICATIONS

Duke Energy and Progress Energy have various financial and performance guarantees and indemnifications, which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, standby letters of credit, debt guarantees, surety bonds and indemnifications. Duke Energy and Progress Energy enter into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. At December 31, 2018, Duke Energy and Progress Energy do not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included on the accompanying Consolidated Balance Sheets.

On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to shareholders. Guarantees issued by Duke Energy or its affiliates, or assigned to Duke Energy prior to the spin-off, remained with Duke Energy subsequent to the spin-off. Guarantees issued by Spectra Capital or its affiliates prior to the spin-off remained with Spectra Capital subsequent to the spin-off, except for guarantees that were later assigned to Duke Energy. Duke Energy has indemnified Spectra Capital against any losses incurred under certain of the guarantee obligations that remain with Spectra Capital. At December 31, 2018, the maximum potential amount of future payments associated with these guarantees was $205 million, the majority of which expires by 2028.

Duke Energy has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly owned entities, as well as guarantees of debt of certain non-consolidated entities and less than wholly owned consolidated entities. If such entities were to default on payments or performance, Duke Energy would be required under the guarantees to make payments on the obligations of the less than wholly owned entity. The maximum potential amount of future payments required under these guarantees as of December 31, 2018, was $296 million. Of this amount, $11 million relates to guarantees issued on behalf of less than wholly owned consolidated entities, with the remainder related to guarantees issued on behalf of third parties and unconsolidated affiliates of Duke Energy. Of the guarantees noted above, $248 million of the guarantees expire between 2019 and 2030, with the remaining performance guarantees having no contractual expiration.

In October 2017, ACP executed a $3.4 billion revolving credit facility with a stated maturity date of October 2021. Duke Energy entered into a guarantee agreement to support its share of the ACP revolving credit facility. Duke Energy's maximum exposure to loss under the terms of the guarantee is $677 million as of December 31, 2018. This amount represents 47 percent of the outstanding borrowings under the credit facility.

Duke Energy guaranteed debt issued by Duke Energy Carolinas of $650 million as of December 31, 2018, and 2017.

Duke Energy has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a wholly owned and former non-wholly owned entity to honor its obligations to a third party. Under these arrangements, Duke Energy has payment obligations that are triggered by a draw by the third party or customer due to the failure of the wholly owned or former non-wholly owned entity to perform according to the terms of its underlying contract. At December 31, 2018, Duke Energy had guaranteed $63 million of outstanding surety bonds, most of which have no set expiration.

Duke Energy uses bank-issued standby letters of credit to secure the performance of wholly owned and non-wholly owned entities to a third party or customer. Under these arrangements, Duke Energy has payment obligations to the issuing bank that are triggered by a draw by the third party or customer due to the failure of the wholly owned or non-wholly owned entity to perform according to the terms of its underlying contract. At December 31, 2018, Duke Energy had issued a total of $454 million in letters of credit, which expire between 2019 and 2022. The unused amount under these letters of credit was $60 million.

Duke Energy recognized $23 million and $21 million, as of December 31, 2018, and 2017, respectively, primarily in Other within Other Noncurrent Liabilities on the Consolidated Balance Sheets, for the guarantees discussed above. As current estimates change, additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded by the Duke Energy Registrants in the future.

 

8. JOINT OWNERSHIP OF GENERATING AND TRANSMISSION FACILITIES

The Duke Energy Registrants maintain ownership interests in certain jointly owned generating and transmission facilities. The Duke Energy Registrants are entitled to a share of the generating capacity and output of each unit equal to their respective ownership interests. The Duke Energy Registrants pay their ownership share of additional construction costs, fuel inventory purchases and operating expenses. The Duke Energy Registrants share of revenues and operating costs of the jointly owned facilities is included within the corresponding line in the Consolidated Statements of Operations. Each participant in the jointly owned facilities must provide its own financing.

 

 

 

 

 

 

 

The following table presents the Duke Energy Registrants' interest of jointly owned plant or facilities and amounts included on the Consolidated Balance Sheets. All facilities are operated by the Duke Energy Registrants and are included in the Electric Utilities and Infrastructure segment.

 

December 31, 2018

 

 

 

 

 

 

 

Construction

 

Ownership

 

Property, Plant

 

Accumulated

 

Work in

(in millions except for ownership interest)

Interest

 

and Equipment

 

Depreciation

 

Progress

Duke Energy Carolinas

 

 

 

 

 

 

 

Catawba (units 1 and 2)(a)

19.25

%

 

$

989

 

 

$

483

 

 

$

17

 

W.S. Lee CC(b)

86.67

%

 

593

 

 

12

 

 

4

 

Duke Energy Indiana

 

 

 

 

 

 

 

Gibson (unit 5)(c)

50.05

%

 

390

 

 

173

 

 

3

 

Vermillion(d)

62.50

%

 

168

 

 

135

 

 

 

Transmission and local facilities(c)

Various

 

5,037

 

 

1,769

 

 

 

(a) Jointly owned with North Carolina Municipal Power Agency Number 1, NCEMC and PMPA.

(b) Jointly owned with NCEMC.

(c) Jointly owned with WVPA and Indiana Municipal Power Agency.

(d) Jointly owned with WVPA.

Effective June 30, 2018, Duke Energy Ohio, Ohio Power Company, and The Dayton Power and Light Company, completed an asset exchange that reallocated their ownership interest in certain jointly owned transmission facilities. This transaction was approved by FERC and PUCO. The transaction eliminated the joint owner relationships for these assets. Assets were exchanged at net book value and the net increase in Duke Energy Ohio's assets are shown within Capital expenditures in Duke Energy Ohio's Consolidated Statements of Cash Flows.

 

9. ASSET RETIREMENT OBLIGATIONS

Duke Energy records an ARO when it has a legal obligation to incur retirement costs associated with the retirement of a long-lived asset and the obligation can be reasonably estimated. Certain assets of the Duke Energy Registrants have an indeterminate life, such as transmission and distribution facilities, and thus the fair value of the retirement obligation is not reasonably estimable. A liability for these AROs will be recorded when a fair value is determinable.

The Duke Energy Registrants’ regulated operations accrue costs of removal for property that does not have an associated legal retirement obligation based on regulatory orders from state commissions. These costs of removal are recorded as a regulatory liability in accordance with regulatory accounting treatment. The Duke Energy Registrants do not accrue the estimated cost of removal for any nonregulated assets. See Note 4 for the estimated cost of removal for assets without an associated legal retirement obligation, which are included in Regulatory liabilities on the Consolidated Balance Sheets.

 

 

 

 

 

 

 

 

The following table presents the AROs recorded on the Consolidated Balance Sheets.

 

December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Decommissioning of nuclear power facilities(a)

$

5,696

 

 

$

2,335

 

 

$

3,209

 

 

$

2,679

 

 

$

530

 

 

$

 

 

$

 

 

$

 

Closure of ash impoundments

4,446

 

 

1,568

 

 

2,123

 

 

2,103

 

 

20

 

 

52

 

 

702

 

 

 

Other(b)

325

 

 

46

 

 

79

 

 

38

 

 

41

 

 

41

 

 

20

 

 

19

 

Total asset retirement obligation

$

10,467

 

 

$

3,949

 

 

$

5,411

 

 

$

4,820

 

 

$

591

 

 

$

93

 

 

$

722

 

 

$

19

 

Less: current portion

919

 

 

290

 

 

514

 

 

509

 

 

5

 

 

6

 

 

109

 

 

 

Total noncurrent asset retirement obligation

$

9,548

 

 

$

3,659

 

 

$

4,897

 

 

$

4,311

 

 

$

586

 

 

$

87

 

 

$

613

 

 

$

19

 

(a) Duke Energy amount includes purchase accounting adjustments related to the merger with Progress Energy.

(b) Primarily includes obligations related to asbestos removal. Duke Energy Ohio and Piedmont also include AROs related to the retirement of natural gas mains and services. Duke Energy includes AROs related to the removal of renewable energy generation assets.

Nuclear Decommissioning Liability

AROs related to nuclear decommissioning are based on site-specific cost studies. The NCUC, PSCSC and FPSC require updated cost estimates for decommissioning nuclear plants every five years.

The following table summarizes information about the most recent site-specific nuclear decommissioning cost studies. Decommissioning costs are stated in 2018 dollars for Duke Energy Carolinas, 2017 dollars for Duke Energy Florida and 2014 dollars for Duke Energy Progress, and include costs to decommission plant components not subject to radioactive contamination.

 

Annual Funding

 

Decommissioning

 

 

(in millions)

Requirement(a)

 

Costs(a)

 

Year of Cost Study

Duke Energy

$

24

 

 

$

8,737

 

 

2014 and 2018

Duke Energy Carolinas(b)(c)

 

 

4,291

 

 

2018

Duke Energy Progress

24

 

 

3,550

 

 

2014

Duke Energy Florida(d)

 

 

896

 

 

2018

(a) Amounts for Progress Energy equal the sum of Duke Energy Progress and Duke Energy Florida.

(b) Decommissioning cost for Duke Energy Carolinas reflects its ownership interest in jointly owned reactors. Other joint owners are responsible for decommissioning costs related to their interest in the reactors.

(c) Duke Energy Carolinas' site-specific nuclear decommissioning cost study completed in 2018 is expected to be filed with the NCUC and PSCSC by the second quarter 2019. Duke Energy Carolinas will also complete a new funding study, which will be completed and filed with the NCUC and PSCSC in 2019.

(d) Duke Energy Florida's site-specific nuclear decommissioning cost study and a new funding study were completed and filed with the FPSC in 2018.

Nuclear Decommissioning Trust Funds

Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida each maintain NDTFs that are intended to pay for the decommissioning costs of their respective nuclear power plants. The NDTF investments are managed and invested in accordance with applicable requirements of various regulatory bodies including the NRC, FERC, NCUC, PSCSC, FPSC and the IRS.

Use of the NDTF investments is restricted to nuclear decommissioning activities including license termination, spent fuel and site restoration. The license termination and spent fuel obligations relate to contaminated decommissioning and are recorded as AROs. The site restoration obligation relates to non-contaminated decommissioning and is recorded to cost of removal within Regulatory liabilities on the Consolidated Balance Sheets.

The following table presents the fair value of NDTF assets legally restricted for purposes of settling AROs associated with nuclear decommissioning. Duke Energy Florida is actively decommissioning Crystal River Unit 3 and was granted an exemption from the NRC, which allows for use of the NDTF for all aspects of nuclear decommissioning. The entire balance of Duke Energy Florida's NDTF may be applied toward license termination, spent fuel and site restoration costs incurred to decommission Crystal River Unit 3 and is excluded from the table below. See Note 16 for additional information related to the fair value of the Duke Energy Registrants' NDTFs.

 

December 31,

(in millions)

2018

 

2017

Duke Energy

$

5,579

 

 

$

5,864

 

Duke Energy Carolinas

3,133

 

 

3,321

 

Duke Energy Progress

2,446

 

 

2,543

 

Nuclear Operating Licenses

Operating licenses for nuclear units are potentially subject to extension. The following table includes the current expiration of nuclear operating licenses.

Unit

Year of Expiration

Duke Energy Carolinas

 

Catawba Units 1 and 2

2043

McGuire Unit 1

2041

McGuire Unit 2

2043

Oconee Units 1 and 2

2033

Oconee Unit 3

2034

Duke Energy Progress

 

Brunswick Unit 1

2036

Brunswick Unit 2

2034

Harris

2046

Robinson

2030

 

The NRC has acknowledged permanent cessation of operation and permanent removal of fuel from the reactor vessel at Crystal River Unit 3. Therefore, the license no longer authorizes operation of the reactor. In January 2018, Crystal River Unit 3 reached a SAFSTOR status.

Closure of Ash Impoundments

The Duke Energy Registrants are subject to state and federal regulations covering the closure of coal ash impoundments, including the EPA CCR rule and the Coal Ash Act, and other agreements. AROs recorded on the Duke Energy Registrants' Consolidated Balance Sheets include the legal obligation for closure of coal ash basins and the disposal of related ash as a result of these regulations and agreements.

The ARO amount recorded on the Consolidated Balance Sheets is based upon estimated closure costs for impacted ash impoundments. The amount recorded represents the discounted cash flows for estimated closure costs based upon either specific closure plans or the probability weightings of the potential closure methods as evaluated on a site-by-site basis. Actual costs to be incurred will be dependent upon factors that vary from site to site. The most significant factors are the method and time frame of closure at the individual sites. Closure methods considered include removing the water from ash basins, consolidating material as necessary and capping the ash with a synthetic barrier, excavating and relocating the ash to a lined structural fill or lined landfill or recycling the ash for concrete or some other beneficial use. The ultimate method and timetable for closure will be in compliance with standards set by federal and state regulations and other agreements. The ARO amount will be adjusted as additional information is gained through the closure and post-closure process, including acceptance and approval of compliance approaches, which may change management assumptions, and may result in a material change to the balance. See ARO Liability Rollforward section below for information on revisions made to the coal ash liability during 2018 and 2017.

Asset retirement costs associated with the AROs for operating plants and retired plants are included in Net property, plant and equipment and Regulatory assets, respectively, on the Consolidated Balance Sheets. See Note 4 for additional information on Regulatory assets related to AROs.

Cost recovery for future expenditures will be pursued through the normal ratemaking process with federal and state utility commissions, which permit recovery of necessary and prudently incurred costs associated with Duke Energy’s regulated operations. See Note 4 for additional information on recovery of coal ash costs.

ARO Liability Rollforward

The following tables present changes in the liability associated with AROs.

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Balance at December 31, 2016

$

10,611

 

 

$

3,895

 

 

$

5,475

 

 

$

4,697

 

 

$

778

 

 

$

77

 

 

$

866

 

 

$

14

 

Accretion expense(a)

435

 

 

184

 

 

228

 

 

195

 

 

33

 

 

3

 

 

32

 

 

1

 

Liabilities settled(b)

(619

)

 

(282

)

 

(270

)

 

(204

)

 

(65

)

 

(7

)

 

(49

)

 

(8

)

Liabilities incurred in the current year(c)

51

 

 

5

 

 

 

 

 

 

 

 

7

 

 

29

 

 

8

 

Revisions in estimates of cash flows

(303

)

 

(192

)

 

(19

)

 

(15

)

 

(4

)

 

4

 

 

(97

)

 

 

Balance at December 31, 2017

10,175

 

 

3,610

 

 

5,414

 

 

4,673

 

 

742

 

 

84

 

 

781

 

 

15

Accretion expense(a)

427

 

 

179

 

 

225

 

 

196

 

 

29

 

 

4

 

 

29

 

 

1

 

Liabilities settled(b)

(638

)

 

(281

)

 

(272

)

 

(227

)

 

(45

)

 

(5

)

 

(79

)

 

 

Liabilities incurred in the current year(c)

39

 

 

8

 

 

5

 

 

 

 

5

 

 

 

 

25

 

 

 

Revisions in estimates of cash flows(d)

464

 

 

433

 

 

39

 

 

178

 

 

(140

)

 

10

 

 

(34

)

 

3

 

Balance at December 31, 2018

$

10,467

 

 

$

3,949

 

 

$

5,411

 

 

$

4,820

 

 

$

591

 

 

$

93

 

 

$

722

 

 

$

19

 

(a) Substantially all accretion expense for the years ended December 31, 2018, and 2017 relates to Duke Energy’s regulated operations and has been deferred in accordance with regulatory accounting treatment.

(b) Amounts primarily relate to ash impoundment closures and nuclear decommissioning of Crystal River Unit 3.

(c) Amounts primarily relate to AROs recorded as a result of state agency closure requirements at Duke Energy Indiana.

(d) Amounts primarily relate to increases in groundwater monitoring estimates for closure of ash impoundments and an increase for nuclear decommissioning costs at Duke Energy Carolinas' nuclear sites compared to original estimates, partially offset by a reduction for nuclear decommissioning at Crystal River Unit 3 compared to original estimates and modifications to the timing of expected cash flows for coal ash AROs.

 

 

 

 

 

 

 

 

10. PROPERTY, PLANT AND EQUIPMENT

The following tables summarize the property, plant and equipment for Duke Energy and its subsidiary registrants.

 

December 31, 2018

 

Estimated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Useful

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Life

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

(Years)

 

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Land

 

 

$

2,072

 

 

$

472

 

 

$

868

 

 

$

445

 

 

$

423

 

 

$

136

 

 

$

116

 

 

$

448

 

Plant – Regulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric generation, distribution and transmission

15-100

 

100,706

 

 

38,468

 

 

42,760

 

 

26,147

 

 

16,613

 

 

5,182

 

 

14,292

 

 

 

Natural gas transmission and distribution

12-80

 

8,808

 

 

 

 

 

 

 

 

 

 

2,719

 

 

 

 

6,089

 

Other buildings and improvements

24-90

 

1,966

 

 

681

 

 

636

 

 

295

 

 

341

 

 

270

 

 

253

 

 

126

 

Plant – Nonregulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric generation, distribution and transmission

5-30

 

4,410

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other buildings and improvements

25-35

 

494

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nuclear fuel

 

 

3,460

 

 

1,898

 

 

1,562

 

 

1,562

 

 

 

 

 

 

 

 

 

Equipment

3-55

 

2,141

 

 

467

 

 

565

 

 

399

 

 

166

 

 

384

 

 

178

 

 

141

 

Construction in process

 

 

5,726

 

 

1,678

 

 

2,515

 

 

1,659

 

 

856

 

 

412

 

 

325

 

 

382

 

Other

3-40

 

4,675

 

 

1,077

 

 

1,354

 

 

952

 

 

393

 

 

257

 

 

279

 

 

300

 

Total property, plant and equipment(a)(d)

 

 

134,458

 

 

44,741

 

 

50,260

 

 

31,459

 

 

18,792

 

 

9,360

 

 

15,443

 

 

7,486

 

Total accumulated depreciation – regulated(b)(c)(d)

 

 

(41,079

)

 

(15,496

)

 

(16,398

)

 

(11,423

)

 

(4,968

)

 

(2,717

)

 

(4,914

)

 

(1,575

)

Total accumulated depreciation – nonregulated(c)(d)

 

 

(2,047

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Generation facilities to be retired, net

 

 

362

 

 

 

 

362

 

 

362

 

 

 

 

 

 

 

 

 

Total net property, plant and equipment

 

 

$

91,694

 

 

$

29,245

 

 

$

34,224

 

 

$

20,398

 

 

$

13,824

 

 

$

6,643

 

 

$

10,529

 

 

$

5,911

 

(a) Includes capitalized leases of $1,237 million, $135 million, $257 million, $137 million, $120 million, $73 million and $35 million at Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio and Duke Energy Indiana, respectively, primarily within Plant – Regulated. The Progress Energy, Duke Energy Progress and Duke Energy Florida amounts are net of $131 million, $14 million and $117 million, respectively, of accumulated amortization of capitalized leases.

(b) Includes $1,947 million, $1,087 million, $860 million and $860 million of accumulated amortization of nuclear fuel at Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively.

(c) Includes accumulated amortization of capitalized leases of $61 million, $12 million, $20 million and $10 million at Duke Energy, Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana, respectively.

(d) Includes gross property, plant and equipment cost of consolidated VIEs of $4,007 million and accumulated depreciation of consolidated VIEs of $698 million at Duke Energy.

 

December 31, 2017

 

Estimated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Useful

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Life

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

(Years)

 

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Land

 

 

$

1,559

 

 

$

467

 

 

$

767

 

 

$

424

 

 

$

343

 

 

$

134

 

 

$

111

 

 

$

41

 

Plant – Regulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric generation, distribution and transmission

8-100

 

93,687

 

 

35,657

 

 

39,419

 

 

24,502

 

 

14,917

 

 

4,870

 

 

13,741

 

 

 

Natural gas transmission and distribution

12-80

 

8,292

 

 

 

 

 

 

 

 

 

 

2,559

 

 

 

 

5,733

 

Other buildings and improvements

15-100

 

1,936

 

 

647

 

 

652

 

 

316

 

 

336

 

 

243

 

 

240

 

 

154

 

Plant – Nonregulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric generation, distribution and transmission(a)

5-30

 

4,273

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other buildings and improvements

25-35

 

465

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nuclear fuel

 

 

3,680

 

 

2,120

 

 

1,560

 

 

1,560

 

 

 

 

 

 

 

 

 

Equipment

3-55

 

2,122

 

 

402

 

 

555

 

 

416

 

 

139

 

 

348

 

 

169

 

 

266

 

Construction in process

 

 

6,995

 

 

2,614

 

 

3,059

 

 

1,434

 

 

1,625

 

 

350

 

 

416

 

 

231

 

Other

3-40

 

4,498

 

 

1,032

 

 

1,311

 

 

931

 

 

370

 

 

228

 

 

271

 

 

300

 

Total property, plant and equipment(b)(e)

 

 

127,507

 

 

42,939

 

 

47,323

 

 

29,583

 

 

17,730

 

 

8,732

 

 

14,948

 

 

6,725

 

Total accumulated depreciation – regulated(c)(d)(e)

 

 

(39,742

)

 

(15,063

)

 

(15,857

)

 

(10,903

)

 

(4,947

)

 

(2,691

)

 

(4,662

)

 

(1,479

)

Total accumulated depreciation – nonregulated(d)(e)

 

 

(1,795

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Generation facilities to be retired, net

 

 

421

 

 

 

 

421

 

 

421

 

 

 

 

 

 

 

 

 

Total net property, plant and equipment

 

 

$

86,391

 

 

$

27,876

 

 

$

31,887

 

 

$

19,101

 

 

$

12,783

 

 

$

6,041

 

 

$

10,286

 

 

$

5,246

 

(a) Includes a pretax impairment charge of $58 million on a wholly owned non-contracted wind project. See discussion below.

(b) Includes capitalized leases of $1,294 million, $81 million, $272 million, $139 million, $133 million, $80 million and $35 million at Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio and Duke Energy Indiana, respectively, primarily within Plant – Regulated. The Progress Energy, Duke Energy Progress and Duke Energy Florida amounts are net of $114 million, $11 million and $103 million, respectively, of accumulated amortization of capitalized leases.

(c) Includes $2,113 million, $1,283 million, $831 million and $831 million of accumulated amortization of nuclear fuel at Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively.

(d) Includes accumulated amortization of capitalized leases of $57 million, $11 million, $21 million and $9 million at Duke Energy, Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana, respectively.

(e) Includes gross property, plant and equipment cost of consolidated VIEs of $3,941 million and accumulated depreciation of consolidated VIEs of $598 million at Duke Energy.

During the year ended December 31, 2017, Duke Energy recorded a pretax impairment charge of $69 million on a wholly owned non-contracted wind project. The impairment was recorded within Impairment charges on Duke Energy’s Consolidated Statements of Operations. $58 million of the impairment related to property, plant and equipment and $11 million of the impairment related to a net intangible asset; see Note 11 for additional information. The charge represents the excess carrying value over the estimated fair value of the project, which was based on a Level 3 Fair Value measurement that was determined from the income approach using discounted cash flows. The impairment was primarily due to the non-contracted wind project being located in a market that has experienced continued declining market pricing during 2017 and declining long-term forecasted energy and capacity prices, driven by low natural gas prices, additional renewable generation placed in service and lack of significant load growth.

The following tables present capitalized interest, which includes the debt component of AFUDC.

 

Years Ended December 31,

(in millions)

2018

 

2017

 

2016

Duke Energy

$

161

 

 

$

128

 

 

$

100

 

Duke Energy Carolinas

35

 

 

45

 

 

38

 

Progress Energy

51

 

 

45

 

 

31

 

Duke Energy Progress

26

 

 

21

 

 

17

 

Duke Energy Florida

25

 

 

24

 

 

14

 

Duke Energy Ohio

17

 

 

10

 

 

8

 

Duke Energy Indiana

27

 

 

9

 

 

7

 

 

 

Years Ended December 31,

 

Two Months Ended December 31,

 

Year Ended

October 31,

(in millions)

2018

 

2017

 

2016

 

2016

Piedmont

$

17

 

 

$

12

 

 

$

2

 

 

$

12

 

Operating Leases

Duke Energy's Commercial Renewables segment operates various renewable energy projects and sells the generated output to utilities, electric cooperatives, municipalities and commercial and industrial customers through long-term contracts. In certain situations, these long-term contracts and the associated renewable energy projects qualify as operating leases. Rental income from these leases is accounted for as Operating Revenues in the Consolidated Statements of Operations. There are no minimum lease payments as all payments are contingent based on actual electricity generated by the renewable energy projects. Contingent lease payments were $268 million, $262 million, and $216 million for the years ended December 31, 2018, 2017 and 2016. As of December 31, 2018, renewable energy projects owned by Duke Energy and accounted for as operating leases had a cost basis of $3,358 million and accumulated depreciation of $602 million. These assets are principally classified as nonregulated electric generation and transmission assets.

 

 

 

 

 

11. GOODWILL AND INTANGIBLE ASSETS

Goodwill

Duke Energy

The following table presents goodwill by reportable segment for Duke Energy included on Duke Energy's Consolidated Balance Sheets at December 31, 2018, and 2017.

 

Electric Utilities

 

Gas Utilities

 

Commercial

 

 

(in millions)

and Infrastructure

 

and Infrastructure

 

Renewables

 

Total

Goodwill Balance at December 31, 2017

$

17,379

 

 

$

1,924

 

 

$

122

 

 

$

19,425

 

Accumulated impairment charges(a)

 

 

 

 

(29

)

 

(29

)

Goodwill balance at December 31, 2017, adjusted for accumulated impairment charges

$

17,379

 

 

$

1,924

 

 

$

93

 

 

$

19,396

 

 

 

 

 

 

 

 

Goodwill Balance at December 31, 2018

$

17,379

 

 

$

1,924

 

 

$

122

 

 

$

19,425

 

Accumulated impairment charges(a)

$

 

 

$

 

 

$

(122

)

 

$

(122

)

Goodwill balance at December 31, 2018, adjusted for accumulated impairment charges

$

17,379

 

 

$

1,924

 

 

$

 

 

$

19,303

 

(a) Duke Energy evaluated the recoverability of goodwill during 2017 and recorded impairment charges of $29 million related to the Energy Management Solutions reporting unit within the Commercial Renewables segment. The fair value of the reporting unit was determined based on the market approach. See "Goodwill Impairment Testing" below for the results of the 2018 goodwill impairment test.

Duke Energy Ohio

Duke Energy Ohio's Goodwill balance of $920 million, allocated $596 million to Electric Utilities and Infrastructure and $324 million to Gas Utilities and Infrastructure, is presented net of accumulated impairment charges of $216 million on the Consolidated Balance Sheets at December 31, 2018, and 2017.

Progress Energy

Progress Energy's Goodwill is included in the Electric Utilities and Infrastructure segment and there are no accumulated impairment charges.

Piedmont

Piedmont's Goodwill is included in the Gas Utilities and Infrastructure segment and there are no accumulated impairment charges.

Goodwill Impairment Testing

Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont are required to perform an annual goodwill impairment test as of the same date each year and, accordingly, perform their annual impairment testing of goodwill as of August 31. Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont update their test between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value.

 

 

 

 

 

In the third quarter of 2018, based on the results of the annual quantitative goodwill impairment test, management determined that the fair value

of the Commercial Renewables reporting unit was below its respective carrying value, including goodwill. Determination of the Commercial Renewables reporting unit fair value was based on an income approach, which estimates the fair value based on discounted future cash flows. The fair value of the Commercial Renewables reporting unit is impacted by several factors, including forecasted tax credit utilization, the cost of capital, current and forecasted solar and wind volumes, and legislative developments. Certain assumptions used in determining the fair value of the reporting unit in the 2018 impairment test changed from those used in the 2017 annual impairment test including the cost of capital as a result of rising interest rates and the timing of tax credit utilization due to tax reform and IRS clarification on bonus depreciation in August 2018. Based on the quantitative impairment test, the estimated fair value of the Commercial Renewables reporting unit was below its carrying value by an immaterial amount but still more than the goodwill balance assigned to the reporting unit. As such, the entire remaining goodwill balance of approximately $93 million was impaired during the third quarter of 2018.

 

The fair value of all other reporting units for Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont exceeded their respective carrying values at the date of the annual impairment analysis.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Intangible Assets

The following tables show the carrying amount and accumulated amortization of intangible assets included in Other within Other Noncurrent Assets on the Consolidated Balance Sheets of the Duke Energy Registrants at December 31, 2018, and 2017.

 

December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Emission allowances

$

18

 

 

$

 

 

$

5

 

 

$

2

 

 

$

3

 

 

$

 

 

$

12

 

 

$

 

Renewable energy certificates

168

 

 

46

 

 

120

 

 

120

 

 

 

 

2

 

 

 

 

 

Natural gas, coal and power contracts

24

 

 

 

 

 

 

 

 

 

 

 

 

24

 

 

 

Renewable operating and development projects

84

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

6

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3

 

Total gross carrying amounts

300

 

 

46

 

 

125

 

 

122

 

 

3

 

 

2

 

 

36

 

 

3

 

Accumulated amortization – natural gas, coal and power contracts

(20

)

 

 

 

 

 

 

 

 

 

 

 

(20

)

 

 

Accumulated amortization – renewable operating and development projects

(29

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated amortization – other

(5

)

 

 

 

 

 

 

 

 

 

 

 

 

 

(3

)

Total accumulated amortization

(54

)

 

 

 

 

 

 

 

 

 

 

 

(20

)

 

(3

)

Total intangible assets, net

$

246

 

 

$

46

 

 

$

125

 

 

$

122

 

 

$

3

 

 

$

2

 

 

$

16

 

 

$

 

 

 

December 31, 2017

 

 

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Emission allowances

$

19

 

 

$

1

 

 

$

5

 

 

$

2

 

 

$

3

 

 

$

 

 

$

13

 

 

$

 

Renewable energy certificates

148

 

 

38

 

 

107

 

 

107

 

 

 

 

3

 

 

 

 

Natural gas, coal and power contracts

24

 

 

 

 

 

 

 

 

 

 

 

 

24

 

 

 

Renewable operating and development projects

79

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

6

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3

 

Total gross carrying amounts

276

 

 

39

 

 

112

 

 

109

 

 

3

 

 

3

 

 

37

 

 

3

 

Accumulated amortization – natural gas, coal and power contracts

(19

)

 

 

 

 

 

 

 

 

 

 

 

(19

)

 

 

Accumulated amortization – renewable operating and development projects

(22

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated amortization – other

(5

)

 

 

 

 

 

 

 

 

 

 

 

 

 

(3

)

Total accumulated amortization

(46

)

 

 

 

 

 

 

 

 

 

 

 

(19

)

 

(3

)

Total intangible assets, net

$

230

 

 

$

39

 

 

$

112

 

 

$

109

 

 

$

3

 

 

$

3

 

 

$

18

 

 

$

 

 

During the year ended December 31, 2017, Duke Energy recorded a pretax impairment charge of $69 million on a wholly owned non-contracted wind project. The impairment was recorded within Impairment charges on Duke Energy’s Consolidated Statements of Operations. $58 million of the impairment related to property, plant and equipment and $11 million of the impairment related to a net intangible asset that was recorded in 2007 when the project was acquired. Prior to the impairment, the gross amount of the intangible asset was $18 million and the accumulated amortization was $7 million. The intangible asset was fully impaired. See Note 10 for additional information.

Amortization Expense

Amortization expense amounts for natural gas, coal and power contracts, renewable operating projects and other intangible assets are immaterial for the years ended December 31, 2018, 2017 and 2016, and are expected to be immaterial for the next five years as of December 31, 2018.

 

12. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

EQUITY METHOD INVESTMENTS

Investments in affiliates that are not controlled by Duke Energy, but over which it has significant influence, are accounted for using the equity method.

The following table presents Duke Energy’s investments in unconsolidated affiliates accounted for under the equity method, as well as the respective equity in earnings, by segment.

 

Years Ended December 31,

 

2018

 

2017

 

2016

 

 

 

Equity in

 

 

 

Equity in

 

 

Equity in

(in millions)

Investments

 

earnings

 

Investments

 

earnings

 

Investments

earnings

Electric Utilities and Infrastructure

$

97

 

 

$

6

 

 

$

89

 

 

$

5

 

 

$

93

 

$

5

 

Gas Utilities and Infrastructure

1,003

 

 

27

 

 

763

 

 

62

 

 

566

 

19

 

Commercial Renewables

201

 

 

(1

)

 

190

 

 

(5

)

 

185

 

(82

)

Other

108

 

 

51

 

 

133

 

 

57

 

 

81

 

43

 

Total

$

1,409

 

 

$

83

 

 

$

1,175

 

 

$

119

 

 

$

925

 

$

(15

)

During the years ended December 31, 2018, 2017 and 2016, Duke Energy received distributions from equity investments of $108 million, $13 million and $31 million, respectively, which are included in Other assets within Cash Flows from Operating Activities on the Consolidated Statements of Cash Flows. During the years ended December 31, 2018, and 2017, Duke Energy received distributions from equity investments of $137 million and $281 million, respectively, which are included in Return of investment capital within Cash Flows from Investing Activities on the Consolidated Statements of Cash Flows.

During the years ended December 31, 2018, and 2017, and the two months ended December 31, 2016, and the year ended October 31, 2016, Piedmont received distributions from equity investments of $1 million, $4 million, $1 million and $26 million, respectively, which are included in Other assets within Cash Flows from Operating Activities and $3 million, $2 million, $1 million and $18 million, respectively, which are included within Cash Flows from Investing Activities on the Consolidated Statements of Cash Flows.

Significant investments in affiliates accounted for under the equity method are discussed below.

Electric Utilities and Infrastructure

Duke Energy owns a 50 percent interest in DATC and in Pioneer, which build, own and operate electric transmission facilities in North America.

 

 

 

Gas Utilities and Infrastructure

The table below outlines Duke Energy's ownership interests in natural gas pipeline companies and natural gas storage facilities.

 

 

 

Investment Amount (in millions)

 

Ownership

 

December 31,

 

December 31,

Entity Name

Interest

 

2018

 

2017

Pipeline Investments

 

 

 

 

 

Atlantic Coast Pipeline, LLC(a)

47

%

 

$

797

 

 

$

397

 

Sabal Trail Transmission, LLC

7.5

%

 

112

 

(d)

219

 

Constitution Pipeline, LLC(a)

24

%

 

25

 

 

81

 

Cardinal Pipeline Company, LLC(b)

21.49

%

 

10

 

 

11

 

Storage Facilities

 

 

 

 

 

Pine Needle LNG Company, LLC(b)

45

%

 

13

 

 

13

 

Hardy Storage Company, LLC(b)

50

%

 

46

 

 

42

 

Total Investments(c)

 

 

$

1,003

 

 

$

763

 

(a) During the year ended December 31, 2017, Piedmont transferred its share of ownership interest in ACP and Constitution to a wholly owned subsidiary of Duke Energy at book value.

(b) Piedmont owns the Cardinal, Pine Needle and Hardy Storage investments.

(c) Duke Energy includes purchase accounting adjustments related to Piedmont.

(d) Sabal Trail returned capital of $112 million during the year ended December 31, 2018.

In October 2017, Duke Energy entered into a guarantee agreement to support its share of the ACP revolving credit facility. See Note 7 for additional information. As a result of the financing, ACP returned capital of $265 million to Duke Energy.

Piedmont sold its 15 percent membership interest in SouthStar on October 3, 2016, for $160 million resulting in an after tax gain of $81 million during the year ended October 31, 2016. Piedmont's Equity in Earnings in SouthStar was $19 million for the year ended October 31, 2016.

During the fourth quarter of 2018, ACP received several adverse court rulings as described in Note 4. As a result, Duke Energy evaluated this investment for impairment and determined that fair value approximated carrying value and therefore no impairment was necessary.

For regulatory matters and other information on the ACP, Sabal Trail and Constitution investments, see Notes 4 and 17.

Commercial Renewables

Duke Energy has a 50 percent interest in DS Cornerstone, LLC, which owns wind farm projects in the U.S.

Impairment of Equity Method Investments

During the year ended December 31, 2018, Duke Energy recorded an OTTI of the Constitution investment of $55 million within Equity in earnings of unconsolidated affiliates on Duke Energy's Consolidated Statements of Operations. The charge represents the excess carrying value over the estimated fair value of the project, which was based on a Level 3 Fair Value measurement that was determined from the income approach using discounted cash flows. The impairment was primarily due to the recent actions taken by the courts and regulators to uphold the NYSDEC's denial of the certification and uncertainty associated with the remaining legal and regulatory challenges. For additional information on the Constitution investment, see Note 4.

During the year ended December 31, 2016, Duke Energy recorded an OTTI of certain wind project investments. The $71 million pretax impairment was recorded within Equity in earnings (losses) of unconsolidated affiliates on Duke Energy's Consolidated Statements of Operations. The other-than-temporary decline in value of these investments was primarily attributable to a sustained decline in market pricing where the wind investments are located, projected net losses for the projects and a reduction in the projected cash distribution to the class of investment owned by Duke Energy.

Other

Duke Energy owns a 17.5 percent indirect interest in NMC, which owns and operates a methanol and MTBE business in Jubail, Saudi Arabia. Duke Energy's economic ownership interest decreased from 25 to 17.5 percent with the successful startup of NMC's polyacetal production facility in 2017. Duke Energy retains 25 percent of the board representation and voting rights of NMC.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

13. RELATED PARTY TRANSACTIONS

The Subsidiary Registrants engage in related party transactions in accordance with the applicable state and federal commission regulations. Refer to the Consolidated Balance Sheets of the Subsidiary Registrants for balances due to or due from related parties. Material amounts related to transactions with related parties included in the Consolidated Statements of Operations and Comprehensive Income are presented in the following table.

 

Years Ended December 31,

(in millions)

2018

 

2017

 

2016

Duke Energy Carolinas

 

 

 

 

 

Corporate governance and shared service expenses(a)

$

985

 

 

$

858

 

 

$

831

 

Indemnification coverages(b)

22

 

 

23

 

 

22

 

JDA revenue(c)

84

 

 

49

 

 

38

 

JDA expense(c)

207

 

 

145

 

 

156

 

Intercompany natural gas purchases(d)

15

 

 

9

 

 

2

 

Progress Energy

 

 

 

 

 

Corporate governance and shared service expenses(a)

$

906

 

 

$

736

 

 

$

710

 

Indemnification coverages(b)

34

 

 

38

 

 

35

JDA revenue(c)

207

 

 

145

 

 

156

 

JDA expense(c)

84

 

 

49

 

 

38

 

Intercompany natural gas purchases(d)

78

 

 

77

 

 

19

 

Duke Energy Progress

 

 

 

 

 

Corporate governance and shared service expenses(a)

$

577

 

 

$

438

 

 

$

397

 

Indemnification coverages(b)

13

 

 

15

 

 

14

 

JDA revenue(c)

207

 

 

145

 

 

156

 

JDA expense(c)

84

 

 

49

 

 

38

 

Intercompany natural gas purchases(d)

78

 

 

77

 

 

19

 

Duke Energy Florida

 

 

 

 

 

Corporate governance and shared service expenses(a)

$

329

 

 

$

298

 

 

$

313

 

Indemnification coverages(b)

21

 

 

23

 

 

21

 

Duke Energy Ohio

 

 

 

 

 

Corporate governance and shared service expenses(a)

$

374

 

 

$

363

 

 

$

356

 

Indemnification coverages(b)

5

 

 

5

 

 

5

 

Duke Energy Indiana

 

 

 

 

 

Corporate governance and shared service expenses(a)

$

405

 

 

$

370

 

 

$

366

 

Indemnification coverages(b)

7

 

 

8

 

 

8

 

Piedmont

 

 

 

 

 

Corporate governance and shared service expenses(a)

$

170

 

 

$

50

 

 

 

Indemnification coverages(b)

2

 

 

2

 

 

 

Intercompany natural gas sales(d)

93

 

 

86

 

 

 

Natural gas storage and transportation costs(e)

25

 

 

25

 

 

 

 

  1. The Subsidiary Registrants are charged their proportionate share of corporate governance and other shared services costs, primarily related to human resources, employee benefits, information technology, legal and accounting fees, as well as other third-party costs. These amounts are primarily recorded in Operation, maintenance and other on the Consolidated Statements of Operations and Comprehensive Income.

  2. The Subsidiary Registrants incur expenses related to certain indemnification coverages through Bison, Duke Energy’s wholly owned captive insurance subsidiary. These expenses are recorded in Operation, maintenance and other on the Consolidated Statements of Operations and Comprehensive Income.

  3. Duke Energy Carolinas and Duke Energy Progress participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customer rates. Revenues from the sale of power and expenses from the purchase of power pursuant to the JDA are recorded in Operating Revenues and Fuel used in electric generation and purchased power, respectively, on the Consolidated Statements of Operations and Comprehensive Income.

  4. Piedmont provides long-term natural gas delivery service to certain Duke Energy Carolinas and Duke Energy Progress natural gas-fired generation facilities. Piedmont records the sales in Operating Revenues, and Duke Energy Carolinas and Duke Energy Progress record the related purchases as a component of Fuel used in electric generation and purchased power on their respective Consolidated Statements of Operations and Comprehensive Income. These intercompany revenues and expenses are eliminated in consolidation. For the two months ended December 31, 2016, and for sales made subsequent to the acquisition for the year ended October 31, 2016, Piedmont recorded $14 million and $7 million, respectively, of natural gas sales with Duke Energy. For sales made prior to the acquisition for the year ended October 31, 2016, Piedmont recorded $74 million of natural gas sales with Duke Energy.

  5. Piedmont has related party transactions as a customer of its equity method investments in Pine Needle, Hardy Storage, and Cardinal natural gas storage and transportation facilities. These expenses are included in Cost of natural gas on Piedmont's Consolidated Statements of Operations and Comprehensive Income. For the two months ended December 31, 2016, and for the year ended October 31, 2016, Piedmont recorded $6 million and $29 million, respectively, of natural gas storage and transportation costs.

In addition to the amounts presented above, the Subsidiary Registrants have other affiliate transactions, including rental of office space, participation in a money pool arrangement, other operational transactions and their proportionate share of certain charged expenses. See Note 6 for more information regarding money pool. These transactions of the Subsidiary Registrants are incurred in the ordinary course of business and are eliminated in consolidation.

As discussed in Note 17, certain trade receivables have been sold by Duke Energy Ohio and Duke Energy Indiana to CRC, an affiliate formed by a subsidiary of Duke Energy. The proceeds obtained from the sales of receivables are largely cash but do include a subordinated note from CRC for a portion of the purchase price.

Intercompany Income Taxes

Duke Energy and the Subsidiary Registrants file a consolidated federal income tax return and other state and jurisdictional returns. The Subsidiary Registrants have a tax sharing agreement with Duke Energy for the allocation of consolidated tax liabilities and benefits. Income taxes recorded represent amounts the Subsidiary Registrants would incur as separate C-Corporations. The following table includes the balance of intercompany income tax receivables and payables for the Subsidiary Registrants.

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

December 31, 2018

 

 

 

 

 

 

 

Intercompany income tax receivable

$

52

 

$

47

 

$

29

 

$

 

$

 

$

8

 

$

 

Intercompany income tax payable

 

 

 

16

 

3

 

 

45

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

 

 

 

 

 

Intercompany income tax receivable

$

 

$

168

 

$

 

$

44

 

$

22

 

$

 

$

7

 

Intercompany income tax payable

44

 

 

21

 

 

 

35

 

 

 

 

14. DERIVATIVES AND HEDGING

The Duke Energy Registrants use commodity and interest rate contracts to manage commodity price risk and interest rate risk. The primary use of commodity derivatives is to hedge the generation portfolio against changes in the prices of electricity and natural gas. Piedmont enters into natural gas supply contracts to provide diversification, reliability and natural gas cost benefits to its customers. Interest rate swaps are used to manage interest rate risk associated with borrowings.

All derivative instruments not identified as NPNS are recorded at fair value as assets or liabilities on the Consolidated Balance Sheets. Cash collateral related to derivative instruments executed under master netting arrangements is offset against the collateralized derivatives on the Consolidated Balance Sheets. The cash impacts of settled derivatives are recorded as operating activities on the Consolidated Statements of Cash Flows.

INTEREST RATE RISK

The Duke Energy Registrants are exposed to changes in interest rates as a result of their issuance or anticipated issuance of variable-rate and fixed-rate debt and commercial paper. Interest rate risk is managed by limiting variable-rate exposures to a percentage of total debt and by monitoring changes in interest rates. To manage risk associated with changes in interest rates, the Duke Energy Registrants may enter into interest rate swaps, U.S. Treasury lock agreements and other financial contracts. In anticipation of certain fixed-rate debt issuances, a series of forward-starting interest rate swaps or Treasury locks may be executed to lock in components of current market interest rates. These instruments are later terminated prior to or upon the issuance of the corresponding debt.

Cash Flow Hedges

For a derivative designated as hedging the exposure to variable cash flows of a future transaction, referred to as a cash flow hedge, the effective portion of the derivative's gain or loss is initially reported as a component of other comprehensive income and subsequently reclassified into earnings once the future transaction impacts earnings. Amounts for interest rate contracts are reclassified to earnings as interest expense over the term of the related debt. Gains and losses reclassified out of AOCI for the years ended December 31, 2018, 2017 and 2016 were not material. Duke Energy's interest rate derivatives designated as hedges include interest rate swaps used to hedge existing debt within the Commercial Renewables business.

Undesignated Contracts

Undesignated contracts primarily include contracts not designated as a hedge because they are accounted for under regulatory accounting or contracts that do not qualify for hedge accounting.

Duke Energy’s interest rate swaps for its regulated operations employ regulatory accounting. With regulatory accounting, the mark-to-market gains or losses on the swaps are deferred as regulatory liabilities or regulatory assets, respectively. Regulatory assets and liabilities are amortized consistent with the treatment of the related costs in the ratemaking process. The accrual of interest on the swaps is recorded as Interest Expense on the Duke Energy Registrant's Consolidated Statements of Operations and Comprehensive Income.

In August 2016, Duke Energy unwound $1.4 billion of forward-starting interest rate swaps associated with the Piedmont acquisition financing. The swaps were considered undesignated as they did not qualify for hedge accounting. Losses on the swaps of $190 million are included within Interest Expense on the Consolidated Statements of Operations for the year ended December 31, 2016. See Note 2 for additional information related to the Piedmont acquisition.

 

 

 

 

 

 

 

 

 

The following tables show notional amounts of outstanding derivatives related to interest rate risk.

 

December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

Cash flow hedges

$

923

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Undesignated contracts

1,721

 

 

300

 

 

1,200

 

 

650

 

 

550

 

 

27

 

Total notional amount(a)

$

2,644

 

 

$

300

 

 

$

1,200

 

 

$

650

 

 

$

550

 

 

$

27

 

 

 

December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

Cash flow hedges(a)

$

660

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Undesignated contracts

927

 

 

400

 

 

500

 

 

250

 

 

250

 

 

27

 

Total notional amount

$

1,587

 

 

$

400

 

 

$

500

 

 

$

250

 

 

$

250

 

 

$

27

 

(a) Duke Energy includes amounts related to consolidated VIEs of $422 million in cash flow hedges and $194 million in undesignated contracts as of December 31, 2018, and $660 million in cash flow hedges as of December 31, 2017.

COMMODITY PRICE RISK

The Duke Energy Registrants are exposed to the impact of changes in the prices of electricity purchased and sold in bulk power markets and coal and natural gas purchases, including Piedmont's natural gas supply contracts. Exposure to commodity price risk is influenced by a number of factors including the term of contracts, the liquidity of markets and delivery locations. For the Subsidiary Registrants, bulk power electricity and coal and natural gas purchases flow through fuel adjustment clauses, formula based contracts or other cost sharing mechanisms. Differences between the costs included in rates and the incurred costs, including undesignated derivative contracts, are largely deferred as regulatory assets or regulatory liabilities. Piedmont policies allow for the use of financial instruments to hedge commodity price risks. The strategy and objective of these hedging programs are to use the financial instruments to reduce gas cost volatility for customers.

 

 

 

 

 

 

 

 

 

 

 

Volumes

The tables below include volumes of outstanding commodity derivatives. Amounts disclosed represent the absolute value of notional volumes of commodity contracts excluding NPNS. The Duke Energy Registrants have netted contractual amounts where offsetting purchase and sale contracts exist with identical delivery locations and times of delivery. Where all commodity positions are perfectly offset, no quantities are shown.

 

December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

 

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Electricity (gigawatt-hours)

15,286

 

 

 

 

 

 

 

 

 

 

1,786

 

 

13,500

 

 

 

Natural gas (millions of dekatherms)

739

 

 

121

 

 

169

 

 

166

 

 

3

 

 

 

 

1

 

 

448

 

 

 

December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

 

 

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Indiana

 

Piedmont

Electricity (gigawatt-hours)

34

 

 

 

 

 

 

 

 

 

 

34

 

 

 

Natural gas (millions of dekatherms)

770

 

 

105

 

 

183

 

 

133

 

 

50

 

 

2

 

 

480

 

LOCATION AND FAIR VALUE OF DERIVATIVE ASSETS AND LIABILITIES RECOGNIZED IN THE CONSOLIDATED BALANCE SHEETS

The following tables show the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the Consolidated Balance Sheets, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative Assets

 

December 31, 2018

 

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

 

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Commodity Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Not Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

$

35

 

 

$

2

 

 

$

2

 

 

$

2

 

 

$

 

 

$

6

 

 

$

23

 

 

$

3

 

Noncurrent

 

4

 

 

1

 

 

2

 

 

2

 

 

 

 

 

 

 

 

 

Total Derivative Assets – Commodity Contracts

 

$

39

 

 

$

3

 

 

$

4

 

 

$

4

 

 

$

 

 

$

6

 

 

$

23

 

 

$

3

 

Interest Rate Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

$

1

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Noncurrent

 

3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Not Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Noncurrent

 

12

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Derivative Assets – Interest Rate Contracts

 

$

18

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Total Derivative Assets

 

$

57

 

 

$

3

 

 

$

4

 

 

$

4

 

 

$

 

 

$

6

 

 

$

23

 

 

$

3

 

 

Derivative Liabilities

 

December 31, 2018

 

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

 

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Commodity Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Not Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

$

33

 

 

$

14

 

 

$

10

 

 

$

5

 

 

$

6

 

 

$

 

 

$

 

 

$

8

 

Noncurrent

 

158

 

 

10

 

 

15

 

 

6

 

 

 

 

 

 

 

 

133

 

Total Derivative Liabilities – Commodity Contracts

 

$

191

 

 

$

24

 

 

$

25

 

 

$

11

 

 

$

6

 

 

$

 

 

$

 

 

$

141

 

Interest Rate Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

$

12

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Noncurrent

 

6

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Not Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

23

 

 

9

 

 

13

 

 

11

 

 

2

 

 

1

 

 

 

 

 

Noncurrent

 

10

 

 

 

 

6

 

 

5

 

 

1

 

 

4

 

 

 

 

 

Total Derivative Liabilities – Interest Rate Contracts

 

$

51

 

 

$

9

 

 

$

19

 

 

$

16

 

 

$

3

 

 

$

5

 

 

$

 

 

$

 

Total Derivative Liabilities

 

$

242

 

 

$

33

 

 

$

44

 

 

$

27

 

 

$

9

 

 

$

5

 

 

$

 

 

$

141

 

 

Derivative Assets

 

December 31, 2017

 

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

 

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Commodity Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Not Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

$

34

 

 

$

2

 

 

$

2

 

 

$

1

 

 

$

1

 

 

$

1

 

 

$

27

 

 

$

2

 

Noncurrent

 

1

 

 

 

 

1

 

 

1

 

 

 

 

 

 

 

 

 

Total Derivative Assets – Commodity Contracts

 

$

35

 

 

$

2

 

 

$

3

 

 

$

2

 

 

$

1

 

 

$

1

 

 

$

27

 

 

$

2

 

Interest Rate Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

$

1

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Noncurrent

 

15

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Derivative Assets – Interest Rate Contracts

 

$

16

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

Total Derivative Assets

 

$

51

 

 

$

2

 

 

$

3

 

 

$

2

 

 

$

1

 

 

$

1

 

 

$

27

 

 

$

2

 

 

Derivative Liabilities

 

December 31, 2017

 

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

 

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Commodity Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Not Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

$

36

 

 

$

6

 

 

$

18

 

 

$

8

 

 

$

10

 

 

$

 

 

$

 

 

$

11

 

Noncurrent

 

146

 

 

4

 

 

10

 

 

4

 

 

 

 

 

 

 

 

131

 

Total Derivative Liabilities – Commodity Contracts

 

$

182

 

 

$

10

 

 

$

28

 

 

$

12

 

 

$

10

 

 

$

 

 

$

 

 

$

142

 

Interest Rate Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

$

29

 

 

$

25

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Noncurrent

 

6

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Not Designated as Hedging Instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

1

 

 

 

 

1

 

 

 

 

 

 

1

 

 

 

 

 

Noncurrent

 

12

 

 

 

 

7

 

 

6

 

 

2

 

 

4

 

 

 

 

 

Total Derivative Liabilities – Interest Rate Contracts

 

$

48

 

 

$

25

 

 

$

8

 

 

$

6

 

 

$

2

 

 

$

5

 

 

$

 

 

$

 

Total Derivative Liabilities

 

$

230

 

 

$

35

 

 

$

36

 

 

$

18

 

 

$

12

 

 

$

5

 

 

$

 

 

$

142

 

 

 

OFFSETTING ASSETS AND LIABILITIES

The following tables present the line items on the Consolidated Balance Sheets where derivatives are reported. Substantially all of Duke Energy's outstanding derivative contracts are subject to enforceable master netting arrangements. The gross amounts offset in the tables below show the effect of these netting arrangements on financial position and include collateral posted to offset the net position. The amounts shown are calculated by counterparty. Accounts receivable or accounts payable may also be available to offset exposures in the event of bankruptcy. These amounts are not included in the tables below.

Derivative Assets

 

December 31, 2018

 

 

 

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

 

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Current

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross amounts recognized

 

$

38

 

 

$

2

 

 

$

2

 

 

$

2

 

 

$

 

 

$

6

 

 

$

23

 

 

$

3

 

Gross amounts offset

 

(3

)

 

(2

)

 

(2

)

 

(2

)

 

 

 

 

 

 

 

 

Net amounts presented in Current Assets: Other

 

$

35

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

6

 

 

$

23

 

 

$

3

 

Noncurrent

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross amounts recognized

 

$

19

 

 

$

1

 

 

$

2

 

 

$

2

 

 

$

 

 

$

 

 

$

 

 

$

 

Gross amounts offset

 

(3

)

 

(1

)

 

(2

)

 

(2

)

 

 

 

 

 

 

 

 

Net amounts presented in Other Noncurrent Assets: Other

 

$

16

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Derivative Liabilities

 

December 31, 2018

 

 

 

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

 

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Current

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross amounts recognized

 

$

68

 

 

$

23

 

 

$

23

 

 

$

16

 

 

$

8

 

 

$

1

 

 

$

 

 

$

8

 

Gross amounts offset

 

(4

)

 

(2

)

 

(2

)

 

(2

)

 

 

 

 

 

 

 

 

Net amounts presented in Current Liabilities: Other

 

$

64

 

 

$

21

 

 

$

21

 

 

$

14

 

 

$

8

 

 

$

1

 

 

$

 

 

$

8

 

Noncurrent

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross amounts recognized

 

$

174

 

 

$

10

 

 

$

21

 

 

$

11

 

 

$

1

 

 

$

4

 

 

$

 

 

$

133

 

Gross amounts offset

 

(3

)

 

(1

)

 

(2

)

 

(2

)

 

 

 

 

 

 

 

 

Net amounts presented in Other Noncurrent Liabilities: Other

 

$

171

 

 

$

9

 

 

$

19

 

 

$

9

 

 

$

1

 

 

$

4

 

 

$

 

 

$

133

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative Assets

 

December 31, 2017

 

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

 

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Current

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross amounts recognized

 

$

35

 

 

$

2

 

 

$

2

 

 

$

1

 

 

$

1

 

 

$

1

 

 

$

27

 

 

$

2

 

Gross amounts offset

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net amounts presented in Current Assets: Other

 

$

35

 

 

$

2

 

 

$

2

 

 

$

1

 

 

$

1

 

 

$

1

 

 

$

27

 

 

$

2

 

Noncurrent

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross amounts recognized

 

$

16

 

 

$

 

 

$

1

 

 

$

1

 

 

$

 

 

$

 

 

$

 

 

$

Gross amounts offset

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net amounts presented in Other Noncurrent Assets: Other

 

$

16

 

 

$

 

 

$

1

 

 

$

1

 

 

$

 

 

$

 

 

$

 

 

$

 

 

Derivative Liabilities

 

December 31, 2017

 

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

 

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Current

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross amounts recognized

 

$

66

 

 

$

31

 

 

$

19

 

 

$

8

 

 

$

10

 

 

$

1

 

 

$

 

 

$

11

 

Gross amounts offset

 

(3

)

 

(2

)

 

(2

)

 

(2

)

 

 

 

 

 

 

 

 

Net amounts presented in Current Liabilities: Other

 

$

63

 

 

$

29

 

 

$

17

 

 

$

6

 

 

$

10

 

 

$

1

 

 

$

 

 

$

11

 

Noncurrent

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross amounts recognized

 

$

164

 

 

$

4

 

 

$

17

 

 

$

10

 

 

$

2

 

 

$

4

 

 

$

 

 

$

131

 

Gross amounts offset

 

(1

)

 

 

 

(1

)

 

(1

)

 

 

 

 

 

 

 

 

Net amounts presented in Other Noncurrent Liabilities: Other

 

$

163

 

 

$

4

 

 

$

16

 

 

$

9

 

 

$

2

 

 

$

4

 

 

$

 

 

$

131

 

 

 

 

 

 

 

OBJECTIVE CREDIT CONTINGENT FEATURES

Certain derivative contracts contain objective credit contingent features. These features include the requirement to post cash collateral or letters of credit if specific events occur, such as a credit rating downgrade below investment grade. The following tables show information with respect to derivative contracts that are in a net liability position and contain objective credit-risk-related payment provisions.

 

December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

Aggregate fair value of derivatives in a net liability position

$

44

 

 

$

19

 

 

$

25

 

 

$

25

 

 

$

 

Fair value of collateral already posted

 

 

 

 

 

 

 

 

 

Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered

44

 

 

19

 

 

25

 

 

25

 

 

 

 

 

December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

Aggregate fair value of derivatives in a net liability position

$

59

 

 

$

35

 

 

$

25

 

 

$

15

 

 

$

10

 

Fair value of collateral already posted

 

 

 

 

 

 

 

 

 

Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered

59

 

 

35

 

 

25

 

 

15

 

 

10

 

The Duke Energy Registrants have elected to offset cash collateral and fair values of derivatives. For amounts to be netted, the derivative and cash collateral must be executed with the same counterparty under the same master netting arrangement.

 

15. INVESTMENTS IN DEBT AND EQUITY SECURITIES

Duke Energy's investments in debt and equity securities are primarily comprised of investments held in (i) the NDTF at Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida, (ii) the grantor trusts at Duke Energy Progress, Duke Energy Florida and Duke Energy Indiana related to OPEB plans and (iii) Bison. The Duke Energy Registrants classify investments in debt securities as AFS and investments in equity securities as FV-NI.

For investments in debt securities classified as AFS, the unrealized gains and losses are included in other comprehensive income until realized, at which time, they are reported though net income. For investments in equity securities classified as FV-NI, both realized and unrealized gains and losses are reported through net income. Substantially all of Duke Energy's investments in debt and equity securities qualify for regulatory accounting, and accordingly, all associated realized and unrealized gains and losses on these investments are deferred as a regulatory asset or liability.

Duke Energy classifies the majority of investments in debt and equity securities as long term, unless otherwise noted.

Investment Trusts

The investments within the NDTF and the Investment Trusts are managed by independent investment managers with discretion to buy, sell and invest pursuant to the objectives set forth by the trust agreements. The Duke Energy Registrants have limited oversight of the day-to-day management of these investments. As a result, the ability to hold investments in unrealized loss positions is outside the control of the Duke Energy Registrants. Accordingly, all unrealized losses associated with debt securities within the Investment Trusts are considered OTTIs and are recognized immediately and deferred to regulatory accounts where appropriate.

 

Other AFS Securities

Unrealized gains and losses on all other AFS securities are included in other comprehensive income until realized, unless it is determined the carrying value of an investment is other-than-temporarily impaired. The Duke Energy Registrants analyze all investment holdings each reporting period to determine whether a decline in fair value should be considered other-than-temporary. If an OTTI exists, the unrealized credit loss is included in earnings. There were no material credit losses as of December 31, 2018, and 2017.

Other Investments amounts are recorded in Other within Other Noncurrent Assets on the Consolidated Balance Sheets.

DUKE ENERGY

The following table presents the estimated fair value of investments in debt and equity securities; equity investments are classified as FV-NI and debt investments are classified as AFS.

 

December 31, 2018

 

December 31, 2017

 

Gross

 

Gross

 

 

 

Gross

 

Gross

 

 

 

Unrealized

 

Unrealized

 

 

 

Unrealized

 

Unrealized

 

 

 

Holding

 

Holding

 

Estimated

 

Holding

 

Holding

 

Estimated

(in millions)

Gains

 

Losses

 

Fair Value

 

Gains

 

Losses

 

Fair Value

NDTF

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

 

 

$

 

 

$

88

 

 

$

 

 

$

 

 

$

115

Equity securities

2,402

 

 

95

 

 

4,475

 

 

2,805

 

 

27

 

 

4,914

 

Corporate debt securities

4

 

 

13

 

 

566

 

 

17

 

 

2

 

 

570

 

Municipal bonds

1

 

 

4

 

 

353

 

 

4

 

 

3

 

 

344

 

U.S. government bonds

14

 

 

12

 

 

1,076

 

 

11

 

 

7

 

 

1,027

 

Other debt securities

 

 

2

 

 

148

 

 

 

 

1

 

 

118

 

Total NDTF Investments

$

2,421

 

 

$

126

 

 

$

6,706

 

 

$

2,837

 

 

$

40

 

 

$

7,088

 

Other Investments

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

 

 

$

 

 

$

22

 

 

$

 

 

$

 

 

$

15

 

Equity securities

36

 

 

1

 

 

99

 

 

59

 

 

 

 

123

 

Corporate debt securities

 

 

2

 

 

60

 

 

1

 

 

 

 

57

 

Municipal bonds

 

 

1

 

 

85

 

 

2

 

 

1

 

 

83

 

U.S. government bonds

1

 

 

 

 

45

 

 

 

 

 

 

41

 

Other debt securities

 

 

1

 

 

58

 

 

 

 

1

 

 

44

 

Total Other Investments

$

37

 

 

$

5

 

 

$

369

 

 

$

62

 

 

$

2

 

 

$

363

 

Total Investments

$

2,458

 

 

$

131

 

 

$

7,075

 

 

$

2,899

 

 

$

42

 

 

$

7,451

 

 

The table below summarizes the maturity date for debt securities.

(in millions)

December 31, 2018

Due in one year or less

$

98

 

Due after one through five years

501

 

Due after five through 10 years

570

 

Due after 10 years

1,222

 

Total

$

2,391

 

Realized gains and losses, which were determined on a specific identification basis, from sales of FV-NI and AFS securities for the year ended December 31, 2018, and from sales of AFS securities for the years ended December 31, 2017, and 2016, were as follows.

 

Year Ended December 31,

(in millions)

2018

FV-NI:

 

Realized gains

$

168

 

Realized losses

126

 

AFS:

 

Realized gains

22

 

Realized losses

51

 

 

 

Years Ended December 31,

(in millions)

2017

 

2016

Realized gains

$

202

 

 

$

246

 

Realized losses

160

 

 

187

 

DUKE ENERGY CAROLINAS

The following table presents the estimated fair value of investments in debt and equity securities; equity investments are classified as FV-NI and debt investments are classified as AFS.

 

December 31, 2018

 

December 31, 2017

 

Gross

 

Gross

 

 

 

Gross

 

Gross

 

 

 

Unrealized

 

Unrealized

 

 

 

Unrealized

 

Unrealized

 

 

 

Holding

 

Holding

 

Estimated

 

Holding

 

Holding

 

Estimated

(in millions)

Gains

 

Losses

 

Fair Value

 

Gains

 

Losses

 

Fair Value

NDTF

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

 

 

$

 

 

$

29

 

 

$

 

 

$

 

 

$

32

 

Equity securities

1,309

 

 

54

 

 

2,484

 

 

1,531

 

 

12

 

 

2,692

 

Corporate debt securities

2

 

 

9

 

 

341

 

 

9

 

 

2

 

 

359

 

Municipal bonds

 

 

1

 

 

81

 

 

 

 

1

 

 

60

 

U.S. government bonds

5

 

 

8

 

 

475

 

 

3

 

 

4

 

 

503

 

Other debt securities

 

 

2

 

 

143

 

 

 

 

1

 

 

112

 

Total NDTF Investments

$

1,316

 

 

$

74

 

 

$

3,553

 

 

$

1,543

 

 

$

20

 

 

$

3,758

 

 

 

 

The table below summarizes the maturity date for debt securities.

(in millions)

December 31, 2018

Due in one year or less

$

6

 

Due after one through five years

142

 

Due after five through 10 years

303

 

Due after 10 years

589

 

Total

$

1,040

 

 

Realized gains and losses, which were determined on a specific identification basis, from sales of FV-NI and AFS securities for the year ended December 31, 2018, and from sales of AFS securities for the years ended December 31, 2017, and 2016, were as follows.

 

Year Ended December 31,

(in millions)

2018

FV-NI:

 

Realized gains

$

89

 

Realized losses

73

 

AFS:

 

Realized gains

19

 

Realized losses

35

 

 

 

Years Ended December 31,

(in millions)

2017

 

2016

Realized gains

$

135

 

 

$

157

 

Realized losses

103

 

 

121

 

 

 

 

 

 

 

 

 

PROGRESS ENERGY

The following table presents the estimated fair value of investments in debt and equity securities; equity investments are classified as FV-NI and debt investments are classified as AFS.

 

December 31, 2018

 

December 31, 2017

 

Gross

 

Gross

 

 

 

Gross

 

Gross

 

 

 

Unrealized

 

Unrealized

 

 

 

Unrealized

 

Unrealized

 

 

 

Holding

 

Holding

 

Estimated

 

Holding

 

Holding

 

Estimated

(in millions)

Gains

 

Losses

 

Fair Value

 

Gains

 

Losses

 

Fair Value

NDTF

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

 

 

$

 

 

$

59

 

 

$

 

 

$

 

 

$

83

 

Equity securities

1,093

 

 

41

 

 

1,991

 

 

1,274

 

 

15

 

 

2,222

 

Corporate debt securities

2

 

 

4

 

 

225

 

 

8

 

 

 

 

211

 

Municipal bonds

1

 

 

3

 

 

272

 

 

4

 

 

2

 

 

284

 

U.S. government bonds

9

 

 

4

 

 

601

 

 

8

 

 

3

 

 

524

 

Other debt securities

 

 

 

 

5

 

 

 

 

 

 

6

 

Total NDTF Investments

$

1,105

 

 

$

52

 

 

$

3,153

 

 

$

1,294

 

 

$

20

 

 

$

3,330

 

Other Investments

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

 

 

$

 

 

$

17

 

 

$

 

 

$

 

 

$

12

 

Municipal bonds

 

 

 

 

47

 

 

2

 

 

 

 

47

 

Total Other Investments

$

 

 

$

 

 

$

64

 

 

$

2

 

 

$

 

 

$

59

 

Total Investments

$

1,105

 

 

$

52

 

 

$

3,217

 

 

$

1,296

 

 

$

20

 

 

$

3,389

 

The table below summarizes the maturity date for debt securities.

(in millions)

December 31, 2018

Due in one year or less

$

87

 

Due after one through five years

306

 

Due after five through 10 years

216

 

Due after 10 years

541

 

Total

$

1,150

 

 

 

 

 

 

Realized gains and losses, which were determined on a specific identification basis, from sales of FV-NI and AFS securities for the year ended December 31, 2018, and from sales of AFS securities for the years ended December 31, 2017, and 2016, were as follows.

 

Year Ended December 31,

(in millions)

2018

FV-NI:

 

Realized gains

$

79

 

Realized losses

53

 

AFS:

 

Realized gains

3

 

Realized losses

15

 

 

 

Years Ended December 31,

(in millions)

2017

 

2016

Realized gains

$

65

 

 

$

84

 

Realized losses

56

 

 

64

 

DUKE ENERGY PROGRESS

The following table presents the estimated fair value of investments in debt and equity securities; equity investments are classified as FV-NI and debt investments are classified as AFS.

 

December 31, 2018

 

December 31, 2017

 

Gross

 

Gross

 

 

 

Gross

 

Gross

 

 

 

Unrealized

 

Unrealized

 

 

 

Unrealized

 

Unrealized

 

 

 

Holding

 

Holding

 

Estimated

 

Holding

 

Holding

 

Estimated

(in millions)

Gains

 

Losses

 

Fair Value

 

Gains

 

Losses

 

Fair Value

NDTF

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

 

 

$

 

 

$

46

 

 

$

 

 

$

 

 

$

50

 

Equity securities

833

 

 

30

 

 

1,588

 

 

980

 

 

12

 

 

1,795

 

Corporate debt securities

2

 

 

3

 

 

171

 

 

6

 

 

 

 

149

 

Municipal bonds

1

 

 

3

 

 

271

 

 

4

 

 

2

 

 

283

 

U.S. government bonds

6

 

 

3

 

 

415

 

 

5

 

 

2

 

 

310

 

Other debt securities

 

 

 

 

3

 

 

 

 

 

 

4

 

Total NDTF Investments

$

842

 

 

$

39

 

 

$

2,494

 

 

$

995

 

 

$

16

 

 

$

2,591

 

Other Investments

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

 

 

$

 

 

$

6

 

 

$

 

 

$

 

 

$

1

 

Total Other Investments

$

 

 

$

 

 

$

6

 

 

$

 

 

$

 

 

$

1

 

Total Investments

$

842

 

 

$

39

 

 

$

2,500

 

 

$

995

 

 

$

16

 

 

$

2,592

 

 

The table below summarizes the maturity date for debt securities.

(in millions)

December 31, 2018

Due in one year or less

$

49

 

Due after one through five years

231

 

Due after five through 10 years

161

 

Due after 10 years

419

 

Total

$

860

 

 

Realized gains and losses, which were determined on a specific identification basis, from sales of FV-NI and AFS securities for the year ended December 31, 2018, and from sales of AFS securities for the years ended December 31, 2017, and 2016, were as follows.

 

Year Ended December 31,

(in millions)

2018

FV-NI:

 

Realized gains

$

68

 

Realized losses

48

 

AFS:

 

Realized gains

$

2

 

Realized losses

10

 

 

 

Years Ended December 31,

(in millions)

2017

 

2016

Realized gains

$

54

 

 

$

71

 

Realized losses

48

 

 

55

 

 

 

 

 

 

 

 

 

DUKE ENERGY FLORIDA

The following table presents the estimated fair value of investments in debt and equity securities; equity investments are classified as FV-NI and debt investments are classified as AFS.

 

December 31, 2018

 

December 31, 2017

 

Gross

 

Gross

 

 

 

Gross

 

Gross

 

 

 

Unrealized

 

Unrealized

 

 

 

Unrealized

 

Unrealized

 

 

 

Holding

 

Holding

 

Estimated

 

Holding

 

Holding

 

Estimated

(in millions)

Gains

 

Losses

 

Fair Value

 

Gains

 

Losses

 

Fair Value

NDTF

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

 

 

$

 

 

$

13

 

 

$

 

 

$

 

 

$

33

 

Equity securities

260

 

 

11

 

 

403

 

 

294

 

 

3

 

 

427

 

Corporate debt securities

 

 

1

 

 

54

 

 

2

 

 

 

 

62

 

Municipal bonds

 

 

 

 

1

 

 

 

 

 

 

1

 

U.S. government bonds

3

 

 

1

 

 

186

 

 

3

 

 

1

 

 

214

 

Other debt securities

 

 

 

 

2

 

 

 

 

 

 

2

 

Total NDTF Investments(a)

$

263

 

 

$

13

 

 

$

659

 

 

$

299

 

 

$

4

 

 

$

739

 

Other Investments

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

 

 

$

 

 

$

1

 

 

$

 

 

$

 

 

$

1

 

Municipal bonds

 

 

 

 

47

 

 

2

 

 

 

 

47

 

Total Other Investments

$

 

 

$

 

 

$

48

 

 

$

2

 

 

$

 

 

$

48

 

Total Investments

$

263

 

 

$

13

 

 

$

707

 

 

$

301

 

 

$

4

 

 

$

787

 

(a) During the year ended December 31, 2018, Duke Energy Florida continued to receive reimbursements from the NDTF for costs related to ongoing decommissioning activity of the Crystal River Unit 3 nuclear plant.

The table below summarizes the maturity date for debt securities.

(in millions)

December 31, 2018

Due in one year or less

$

38

 

Due after one through five years

75

 

Due after five through 10 years

55

 

Due after 10 years

122

 

Total

$

290

 

 

 

 

 

Realized gains and losses, which were determined on a specific identification basis, from sales of FV-NI and AFS securities for the year ended December 31, 2018, and from sales of AFS securities for the years ended December 31, 2017, and 2016, were as follows.

 

Year Ended December 31,

(in millions)

2018

FV-NI:

 

Realized gains

$

11

 

Realized losses

5

 

AFS:

 

Realized gains

1

 

Realized losses

5

 

 

 

Years Ended December 31,

(in millions)

2017

 

2016

Realized gains

$

11

 

 

$

13

 

Realized losses

8

 

 

9

 

DUKE ENERGY INDIANA

The following table presents the estimated fair value of investments in debt and equity securities; equity investments are measured at FV-NI and debt investments are classified as AFS.

 

December 31, 2018

 

December 31, 2017

 

Gross

 

Gross

 

 

 

Gross

 

Gross

 

 

Unrealized

 

Unrealized

 

 

 

Unrealized

 

Unrealized

 

 

 

Holding

 

Holding

 

Estimated

 

Holding

 

Holding

 

Estimated

(in millions)

Gains

 

Losses

 

Fair Value

 

Gains

 

Losses

 

Fair Value

Investments

 

 

 

 

 

 

 

 

 

 

 

Equity securities

$

29

 

 

$

 

 

$

67

 

 

$

49

 

 

$

 

 

$

97

 

Corporate debt securities

 

 

 

 

8

 

 

 

 

 

 

3

 

Municipal bonds

 

 

1

 

 

33

 

 

 

 

1

 

 

28

 

Total Investments

$

29

 

 

$

1

 

 

$

108

 

 

$

49

 

 

$

1

 

 

$

128

 

The table below summarizes the maturity date for debt securities.

(in millions)

December 31, 2018

Due in one year or less

$

3

 

Due after one through five years

20

 

Due after five through 10 years

4

 

Due after 10 years

14

 

Total

$

41

 

Realized gains and losses, which were determined on a specific identification basis, from sales of FV-NI and AFS securities for the year ended December 31, 2018, and from sales of AFS securities for the years ended December 31, 2017, and 2016, were insignificant.

 

16. FAIR VALUE MEASUREMENTS

Fair value is the exchange price to sell an asset or transfer a liability in an orderly transaction between market participants at the measurement date. The fair value definition focuses on an exit price versus the acquisition cost. Fair value measurements use market data or assumptions market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs may be readily observable, corroborated by market data, or generally unobservable. Valuation techniques maximize the use of observable inputs and minimize use of unobservable inputs. A midmarket pricing convention (the midpoint price between bid and ask prices) is permitted for use as a practical expedient.

Fair value measurements are classified in three levels based on the fair value hierarchy as defined by GAAP. Certain investments are not categorized within the fair value hierarchy. These investments are measured at fair value using the NAV per share practical expedient. The NAV is derived based on the investment cost, less any impairment, plus or minus changes resulting from observable price changes for an identical or similar investment of the same issuer.

Fair value accounting guidance permits entities to elect to measure certain financial instruments that are not required to be accounted for at fair value, such as equity method investments or the company’s own debt, at fair value. The Duke Energy Registrants have not elected to record any of these items at fair value.

Transfers between levels represent assets or liabilities that were previously (i) categorized at a higher level for which the inputs to the estimate became less observable or (ii) classified at a lower level for which the inputs became more observable during the period. The Duke Energy Registrant’s policy is to recognize transfers between levels of the fair value hierarchy at the end of the period. There were no transfers between levels during the years ended December 31, 2018, 2017 and 2016. In addition, for Piedmont, there were no transfers between levels during the two months ended December 31, 2016, and the year ended October 31, 2016.

Valuation methods of the primary fair value measurements disclosed below are as follows.

Investments in equity securities

The majority of investments in equity securities are valued using Level 1 measurements. Investments in equity securities are typically valued at the closing price in the principal active market as of the last business day of the quarter. Principal active markets for equity prices include published exchanges such as the NYSE and the Nasdaq Stock Market. Foreign equity prices are translated from their trading currency using the currency exchange rate in effect at the close of the principal active market. There was no after-hours market activity that was required to be reflected in the reported fair value measurements.

Investments in debt securities

Most investments in debt securities are valued using Level 2 measurements because the valuations use interest rate curves and credit spreads applied to the terms of the debt instrument (maturity and coupon interest rate) and consider the counterparty credit rating. If the market for a particular fixed-income security is relatively inactive or illiquid, the measurement is Level 3.

Commodity derivatives

Commodity derivatives with clearinghouses are classified as Level 1. Other commodity derivatives, including Piedmont's natural gas supply contracts, are primarily valued using internally developed discounted cash flow models that incorporate forward price, adjustments for liquidity (bid-ask spread) and credit or non-performance risk (after reflecting credit enhancements such as collateral), and are discounted to present value. Pricing inputs are derived from published exchange transaction prices and other observable data sources. In the absence of an active market, the last available price may be used. If forward price curves are not observable for the full term of the contract and the unobservable period had more than an insignificant impact on the valuation, the commodity derivative is classified as Level 3. In isolation, increases (decreases) in natural gas forward prices result in favorable (unfavorable) fair value adjustments for natural gas purchase contracts; and increases (decreases) in electricity forward prices result in unfavorable (favorable) fair value adjustments for electricity sales contracts. Duke Energy regularly evaluates and validates pricing inputs used to estimate the fair value of natural gas commodity contracts by a market participant price verification procedure. This procedure provides a comparison of internal forward commodity curves to market participant generated curves.

Interest rate derivatives

Most over-the-counter interest rate contract derivatives are valued using financial models that utilize observable inputs for similar instruments and are classified as Level 2. Inputs include forward interest rate curves, notional amounts, interest rates and credit quality of the counterparties.

Other fair value considerations

See Note 11 for a discussion of the valuation of goodwill and intangible assets.

DUKE ENERGY

The following tables provide recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets. Derivative amounts in the tables below for all Duke Energy Registrants exclude cash collateral, which is disclosed in Note 14. See Note 15 for additional information related to investments by major security type for the Duke Energy Registrants.

 

December 31, 2018

(in millions)

Total Fair Value

Level 1

Level 2

Level 3

Not Categorized

NDTF equity securities

$

4,475

 

$

4,410

 

$

 

$

 

$

65

 

NDTF debt securities

2,231

 

576

 

1,655

 

 

 

Other equity securities

99

 

99

 

 

 

 

Other debt securities

270

 

67

 

203

 

 

 

Derivative assets

57

 

4

 

25

 

28

 

 

Total assets

7,132

 

5,156

 

1,883

 

28

 

65

 

Derivative liabilities

(242

)

(11

)

(90

)

(141

)

 

Net assets (liabilities)

$

6,890

 

$

5,145

 

$

1,793

 

$

(113

)

$

65

 

 

 

 

December 31, 2017

(in millions)

Total Fair Value

Level 1

Level 2

Level 3

Not Categorized

NDTF equity securities

$

4,914

 

$

4,840

 

$

 

$

 

$

74

 

NDTF debt securities

2,174

 

635

 

1,539

 

 

 

Other equity securities

123

 

123

 

 

 

 

Other debt securities

241

 

57

 

184

 

 

 

Derivative assets

51

 

3

 

20

 

28

 

 

Total assets

7,503

 

5,658

 

1,743

 

28

 

74

 

Derivative liabilities

(230

)

(2

)

(86

)

(142

)

 

Net assets (liabilities)

$

7,273

 

$

5,656

 

$

1,657

 

$

(114

)

$

74

 

 

 

 

 

 

 

 

The following tables provide reconciliations of beginning and ending balances of assets and liabilities measured at fair value using Level 3 measurements. Amounts included in earnings for derivatives are primarily included in Cost of natural gas on the Duke Energy Registrants' Consolidated Statements of Operations and Comprehensive Income. Amounts included in changes of net assets on the Duke Energy Registrants' Consolidated Balance Sheets are included in regulatory assets or liabilities. All derivative assets and liabilities are presented on a net basis.

 

December 31, 2018

 

December 31, 2017

 

 

 

 

 

 

 

 

(in millions)

Derivatives (net)

 

Investments

 

Derivatives (net)

 

Total

Balance at beginning of period

$

(114

)

 

$

5

 

 

$

(166

)

 

$

(161

)

Total pretax realized or unrealized gains included in comprehensive income

 

 

1

 

 

 

 

1

 

Purchases, sales, issuances and settlements:

 

 

 

 

 

 

 

Purchases

57

 

 

 

 

55

 

 

55

 

Sales

 

 

(6

)

 

 

 

(6

)

Settlements

(57

)

 

 

 

(47

)

 

(47

)

Total gains included on the Consolidated Balance Sheet

1

 

 

 

 

44

 

 

44

 

Balance at end of period

$

(113

)

 

$

 

 

$

(114

)

 

$

(114

)

DUKE ENERGY CAROLINAS

The following tables provide recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.

 

December 31, 2018

(in millions)

Total Fair Value

Level 1

Level 2

Not Categorized

NDTF equity securities

$

2,484

 

$

2,419

 

$

 

$

65

 

NDTF debt securities

1,069

 

149

 

920

 

 

Derivative assets

3

 

 

3

 

 

Total assets

3,556

 

2,568

 

923

 

65

 

Derivative liabilities

(33

)

 

(33

)

 

Net assets

$

3,523

 

$

2,568

 

$

890

 

$

65

 

 

 

December 31, 2017

(in millions)

Total Fair Value

Level 1

Level 2

Not Categorized

NDTF equity securities

$

2,692

 

$

2,618

 

$

 

$

74

 

NDTF debt securities

1,066

 

204

 

862

 

 

Derivative assets

2

 

 

2

 

 

Total assets

3,760

 

2,822

 

864

 

74

 

Derivative liabilities

(35

)

(1

)

(34

)

 

Net assets

$

3,725

 

$

2,821

 

$

830

 

$

74

 

 

 

The following table provides reconciliations of beginning and ending balances of assets and liabilities measured at fair value using Level 3 measurements.

 

Investments

 

Year Ended December 31,

(in millions)

2017

Balance at beginning of period

$

3

 

Total pretax realized or unrealized gains included in comprehensive income

1

 

Purchases, sales, issuances and settlements:

 

Sales

(4

)

Balance at end of period

$

 

PROGRESS ENERGY

The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.

 

December 31, 2018

 

December 31, 2017

(in millions)

Total Fair Value

Level 1

Level 2

 

Total Fair Value

Level 1

Level 2

NDTF equity securities

$

1,991

 

$

1,991

 

$

 

 

$

2,222

 

$

2,222

 

$

 

NDTF debt securities

1,162

 

427

 

735

 

 

1,108

 

431

 

677

 

Other debt securities

64

 

17

 

47

 

 

59

 

12

 

47

 

Derivative assets

4

 

 

4

 

 

3

 

1

 

2

 

Total assets

3,221

 

2,435

 

786

 

 

3,392

 

2,666

 

726

 

Derivative liabilities

(44

)

 

(44

)

 

(36

)

(1

)

(35

)

Net assets

$

3,177

 

$

2,435

 

$

742

 

 

$

3,356

 

$

2,665

 

$

691

 

DUKE ENERGY PROGRESS

The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.

 

December 31, 2018

 

December 31, 2017

(in millions)

Total Fair Value

Level 1

Level 2

 

Total Fair Value

Level 1

Level 2

NDTF equity securities

$

1,588

 

$

1,588

 

$

 

 

$

1,795

 

$

1,795

 

$

 

NDTF debt securities

906

 

294

 

612

 

 

796

 

243

 

553

 

Other debt securities

6

 

6

 

 

 

1

 

1

 

 

Derivative assets

4

 

 

4

 

 

2

 

1

 

1

 

Total assets

2,504

 

1,888

 

616

 

 

2,594

 

2,040

 

554

 

Derivative liabilities

(27

)

 

(27

)

 

(18

)

(1

)

(17

)

Net assets

$

2,477

 

$

1,888

 

$

589

 

 

$

2,576

 

$

2,039

 

$

537

 

 

DUKE ENERGY FLORIDA

The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.

 

December 31, 2018

 

December 31, 2017

(in millions)

Total Fair Value

Level 1

Level 2

 

Total Fair Value

Level 1

Level 2

NDTF equity securities

$

403

 

$

403

 

$

 

 

$

427

 

$

427

 

$

 

NDTF debt securities

256

 

133

 

123

 

 

312

 

188

 

124

 

Other debt securities

48

 

1

 

47

 

 

48

 

1

 

47

 

Derivative assets

 

 

 

 

1

 

 

1

 

Total assets

707

 

537

 

170

 

 

788

 

616

 

172

 

Derivative liabilities

(9

)

 

(9

)

 

(12

)

 

(12

)

Net assets

$

698

 

$

537

 

$

161

 

 

$

776

 

$

616

 

$

160

 

 

DUKE ENERGY OHIO

The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.

 

December 31, 2018

 

December 31, 2017

(in millions)

Total Fair Value

Level 2

Level 3

 

Total Fair Value

Level 2

Level 3

Derivative assets

$

6

 

$

 

$

6

 

 

$

1

 

$

 

$

1

 

Derivative liabilities

(5

)

(5

)

 

 

(5

)

(5

)

 

Net assets (liabilities)

$

1

 

$

(5

)

$

6

 

 

$

(4

)

$

(5

)

$

1

 

The following table provides a reconciliation of beginning and ending balances of assets and liabilities measured at fair value using Level 3 measurements.

 

Derivatives (net)

 

Years Ended December 31,

(in millions)

2018

 

2017

Balance at beginning of period

$

1

 

 

$

5

 

Purchases, sales, issuances and settlements:

 

 

 

Purchases

7

 

 

3

 

Settlements

(4

)

 

(4

)

Total gains included on the Consolidated Balance Sheet

2

 

 

(3

)

Balance at end of period

$

6

 

 

$

1

 

 

 

DUKE ENERGY INDIANA

The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.

 

December 31, 2018

 

December 31, 2017

(in millions)

Total Fair Value

Level 1

Level 2

Level 3

 

Total Fair Value

Level 1

Level 2

Level 3

Other equity securities

$

67

 

$

67

 

$

 

$

 

 

$

97

 

$

97

 

$

 

$

 

Other debt securities

41

 

 

41

 

 

 

31

 

 

31

 

 

Derivative assets

23

 

1

 

 

22

 

 

27

 

 

 

27

 

Total assets

$

131

 

$

68

 

$

41

 

$

22

 

 

$

155

 

$

97

 

$

31

 

$

27

 

The following table provides a reconciliation of beginning and ending balances of assets and liabilities measured at fair value using Level 3 measurements.

 

Derivatives (net)

 

Years Ended December 31,

(in millions)

2018

 

2017

Balance at beginning of period

$

27

 

 

$

16

 

Purchases, sales, issuances and settlements:

 

 

 

Purchases

50

 

 

52

 

Settlements

(53

)

 

(43

)

Total (losses) gains included on the Consolidated Balance Sheet

(2

)

 

2

 

Balance at end of period

$

22

 

 

$

27

 

 

PIEDMONT

The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets.

 

December 31, 2018

 

December 31, 2017

(in millions)

Total Fair Value

Level 1

Level 3

 

Total Fair Value

Level 1

Level 3

Other debt securities

$

 

$

 

$

 

 

$

1

 

$

1

 

$

 

Derivative assets

3

 

3

 

 

 

2

 

2

 

 

Total assets

3

 

3

 

 

 

3

 

3

 

 

Derivative liabilities

(141

)

 

(141

)

 

(142

)

 

(142

)

Net (liabilities) assets

$

(138

)

$

3

 

$

(141

)

 

$

(139

)

$

3

 

$

(142

)

 

 

 

The following table provides a reconciliation of beginning and ending balances of assets and liabilities measured at fair value using Level 3 measurements.

 

Derivatives (net)

 

Years Ended December 31,

(in millions)

2018

 

2017

Balance at beginning of period

$

(142

)

 

$

(187

)

Total gains and settlements

1

 

 

45

 

Balance at end of period

$

(141

)

 

$

(142

)

 

QUANTITATIVE INFORMATION ABOUT UNOBSERVABLE INPUTS

The following tables include quantitative information about the Duke Energy Registrants' derivatives classified as Level 3.

 

December 31, 2018

 

Fair Value

 

 

 

 

 

Investment Type

(in millions)

Valuation Technique

Unobservable Input

Range

Duke Energy Ohio

 

 

 

 

 

 

FTRs

$

6

 

RTO auction pricing

FTR price – per MWh

$

1.19

 

$

4.59

 

Duke Energy Indiana

 

 

 

 

 

 

FTRs

22

 

RTO auction pricing

FTR price – per MWh

(2.07

)

8.27

 

Piedmont

 

 

 

 

 

 

Natural gas contracts

(141

)

Discounted cash flow

Forward natural gas curves — price per MMBtu

1.87

 

2.95

 

Duke Energy

 

 

 

 

 

 

Total Level 3 derivatives

$

(113

)

 

 

 

 

 

 

 

December 31, 2017

 

Fair Value

 

 

 

 

 

Investment Type

(in millions)

Valuation Technique

Unobservable Input

Range

Duke Energy Ohio

 

 

 

 

 

 

FTRs

$

1

 

RTO auction pricing

FTR price – per MWh

$

0.07

 

$

1.41

 

Duke Energy Indiana

 

 

 

 

 

 

FTRs

27

 

RTO auction pricing

FTR price – per MWh

(0.77

)

7.44

 

Piedmont

 

 

 

 

 

 

Natural gas contracts

(142

)

Discounted cash flow

Forward natural gas curves — price per MMBtu

2.10

 

2.88

 

Duke Energy

 

 

 

 

 

 

Total Level 3 derivatives

$

(114

)

 

 

 

 

 

 

 

 

OTHER FAIR VALUE DISCLOSURES

The fair value and book value of long-term debt, including current maturities, is summarized in the following table. Estimates determined are not necessarily indicative of amounts that could have been settled in current markets. Fair value of long-term debt uses Level 2 measurements.

 

December 31, 2018

 

December 31, 2017

(in millions)

Book Value

 

Fair Value

 

Book Value

 

Fair Value

Duke Energy(a)

$

54,529

 

 

$

54,534

 

 

$

52,279

 

 

$

55,331

 

Duke Energy Carolinas

10,939

 

 

11,471

 

 

10,103

 

 

11,372

 

Progress Energy

18,911

 

 

19,885

 

 

17,837

 

 

20,000

 

Duke Energy Progress

8,204

 

 

8,300

 

 

7,357

 

 

7,992

 

Duke Energy Florida

7,321

 

 

7,742

 

 

7,095

 

 

7,953

 

Duke Energy Ohio

2,165

 

 

2,239

 

 

2,067

 

 

2,249

 

Duke Energy Indiana

3,782

 

 

4,158

 

 

3,783

 

 

4,464

 

Piedmont

2,138

 

 

2,180

 

 

2,037

 

 

2,209

 

(a) Book value of long-term debt includes $1.6 billion as of December 31, 2018, and $1.7 billion as of December 31, 2017, of unamortized debt discount and premium, net in purchase accounting adjustments related to the mergers with Progress Energy and Piedmont that are excluded from fair value of long-term debt.

At both December 31, 2018, and December 31, 2017, fair value of cash and cash equivalents, accounts and notes receivable, accounts payable, notes payable and commercial paper, and nonrecourse notes payable of VIEs are not materially different from their carrying amounts because of the short-term nature of these instruments and/or because the stated rates approximate market rates.

 

17. VARIABLE INTEREST ENTITIES

A VIE is an entity that is evaluated for consolidation using more than a simple analysis of voting control. The analysis to determine whether an entity is a VIE considers contracts with an entity, credit support for an entity, the adequacy of the equity investment of an entity and the relationship of voting power to the amount of equity invested in an entity. This analysis is performed either upon the creation of a legal entity or upon the occurrence of an event requiring reevaluation, such as a significant change in an entity’s assets or activities. A qualitative analysis of control determines the party that consolidates a VIE. This assessment is based on (i) what party has the power to direct the activities of the VIE that most significantly impact its economic performance and (ii) what party has rights to receive benefits or is obligated to absorb losses that could potentially be significant to the VIE. The analysis of the party that consolidates a VIE is a continual reassessment.

CONSOLIDATED VIEs

The obligations of these VIEs discussed in the following paragraphs are nonrecourse to the Duke Energy Registrants. The registrants have no requirement to provide liquidity to, purchase assets of or guarantee performance of these VIEs unless noted in the following paragraphs.

No financial support was provided to any of the consolidated VIEs during the years ended December 31, 2018, 2017 and 2016, or is expected to be provided in the future, that was not previously contractually required.

Receivables Financing – DERF/DEPR/DEFR

DERF, DEPR and DEFR are bankruptcy remote, special purpose subsidiaries of Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida, respectively. DERF, DEPR and DEFR are wholly owned limited liability companies with separate legal existence from their parent companies and their assets are not generally available to creditors of their parent companies. On a revolving basis, DERF, DEPR and DEFR buy certain accounts receivable arising from the sale of electricity and related services from their parent companies.

DERF, DEPR and DEFR borrow amounts under credit facilities to buy these receivables. Borrowing availability from the credit facilities is limited to the amount of qualified receivables purchased. The sole source of funds to satisfy the related debt obligations is cash collections from the receivables. Amounts borrowed under the credit facilities are reflected on the Consolidated Balance Sheets as Long-Term Debt.

The most significant activity that impacts the economic performance of DERF, DEPR and DEFR are the decisions made to manage delinquent receivables. Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida are considered the primary beneficiaries and consolidate DERF, DEPR and DEFR, respectively, as they make those decisions.

Receivables Financing – CRC

CRC is a bankruptcy remote, special purpose entity indirectly owned by Duke Energy. On a revolving basis, CRC buys certain accounts receivable arising from the sale of electricity, natural gas and related services from Duke Energy Ohio and Duke Energy Indiana. CRC borrows amounts under a credit facility to buy the receivables from Duke Energy Ohio and Duke Energy Indiana. Borrowing availability from the credit facility is limited to the amount of qualified receivables sold to CRC. The sole source of funds to satisfy the related debt obligation is cash collections from the receivables. Amounts borrowed under the credit facility are reflected on Duke Energy's Consolidated Balance Sheets as Long-Term Debt.

The proceeds Duke Energy Ohio and Duke Energy Indiana receive from the sale of receivables to CRC are approximately 75 percent cash and 25 percent in the form of a subordinated note from CRC. The subordinated note is a retained interest in the receivables sold. Depending on collection experience, additional equity infusions to CRC may be required by Duke Energy to maintain a minimum equity balance of $3 million.

CRC is considered a VIE because (i) equity capitalization is insufficient to support its operations, (ii) power to direct the activities that most significantly impact the economic performance of the entity are not performed by the equity holder and (iii) deficiencies in net worth of CRC are funded by Duke Energy. The most significant activities that impact the economic performance of CRC are decisions made to manage delinquent receivables. Duke Energy is considered the primary beneficiary and consolidates CRC as it makes these decisions. Neither Duke Energy Ohio nor Duke Energy Indiana consolidate CRC.

Receivables Financing – Credit Facilities

The following table outlines amounts and expiration dates of the credit facilities described above.

 

Duke Energy

 

 

 

Duke Energy

 

Duke Energy

 

Duke Energy

 

 

 

Carolinas

 

Progress

 

Florida

 

CRC

 

DERF

 

DEPR

 

DEFR

Expiration date

December 2020

 

December 2020

 

February 2021

 

April 2021

Credit facility amount (in millions)

$

325

 

 

$

450

 

 

$

300

 

 

$

225

Amounts borrowed at December 31, 2018

325

 

 

450

 

 

300

 

 

225

 

Amounts borrowed at December 31, 2017

325

 

 

450

 

 

300

 

 

225

 

Restricted Receivables at December 31, 2018

564

 

 

699

 

 

547

 

 

357

 

Restricted Receivables at December 31, 2017

545

 

 

640

 

 

459

 

 

317

 

Nuclear Asset-Recovery Bonds – DEFPF

DEFPF is a bankruptcy remote, wholly owned special purpose subsidiary of Duke Energy Florida. DEFPF was formed in 2016 for the sole purpose of issuing nuclear asset-recovery bonds to finance Duke Energy Florida's unrecovered regulatory asset related to Crystal River Unit 3.

In 2016, DEFPF issued senior secured bonds and used the proceeds to acquire nuclear asset-recovery property from Duke Energy Florida. The nuclear asset-recovery property acquired includes the right to impose, bill, collect and adjust a non-bypassable nuclear asset-recovery charge from all Duke Energy Florida retail customers until the bonds are paid in full and all financing costs have been recovered. The nuclear asset-recovery bonds are secured by the nuclear asset-recovery property and cash collections from the nuclear asset-recovery charges are the sole source of funds to satisfy the debt obligation. The bondholders have no recourse to Duke Energy Florida. For additional information see Notes 4 and 6.

DEFPF is considered a VIE primarily because the equity capitalization is insufficient to support its operations. Duke Energy Florida has the power to direct the significant activities of the VIE as described above and therefore Duke Energy Florida is considered the primary beneficiary and consolidates DEFPF.

 

 

The following table summarizes the impact of DEFPF on Duke Energy Florida's Consolidated Balance Sheets.

(in millions)

December 31, 2018

December 31, 2017

Receivables of VIEs

$

5

 

$

4

 

Regulatory Assets: Current

52

 

51

 

Current Assets: Other

39

 

40

 

Other Noncurrent Assets: Regulatory assets

1,041

 

1,091

 

Current Liabilities: Other

10

 

10

 

Current maturities of long-term debt

53

 

53

 

Long-Term Debt

1,111

 

1,164

 

Commercial Renewables

Certain of Duke Energy’s renewable energy facilities are VIEs due to Duke Energy issuing guarantees for debt service and operations and maintenance reserves in support of debt financings. Assets are restricted and cannot be pledged as collateral or sold to third parties without prior approval of debt holders. Additionally, Duke Energy has VIEs associated with tax equity arrangements entered into with third–party investors in order to finance the cost of solar energy systems eligible for tax credits. The activities that most significantly impacted the economic performance of these renewable energy facilities were decisions associated with siting, negotiating PPAs and EPC agreements, and decisions associated with ongoing operations and maintenance-related activities. Duke Energy is considered the primary beneficiary and consolidates the entities as it is responsible for all of these decisions.

The table below presents material balances reported on Duke Energy's Consolidated Balance Sheets related to renewables VIEs.

(in millions)

December 31, 2018

December 31, 2017

Current Assets: Other

$

123

 

$

174

 

Property, plant and equipment, cost

4,007

 

3,923

 

Accumulated depreciation and amortization

(698

)

(591

)

Other Noncurrent Assets: Other

261

 

50

 

Current maturities of long-term debt

174

 

170

 

Long-Term Debt

1,587

 

1,700

 

Other Noncurrent Liabilities: Deferred income taxes

 

(148

)

Other Noncurrent Liabilities: Asset Retirement Obligations

106

 

83

 

Other Noncurrent Liabilities: Other

212

 

241

 

 

 

 

 

 

 

NON-CONSOLIDATED VIEs

The following tables summarize the impact of non-consolidated VIEs on the Consolidated Balance Sheets.

 

December 31, 2018

 

Duke Energy

 

Duke

 

Duke

 

Pipeline

 

Commercial

 

Other

 

 

 

Energy

 

Energy

(in millions)

Investments

 

Renewables

 

VIEs

 

Total

 

Ohio

 

Indiana

Receivables from affiliated companies

$

 

 

$

 

 

$

 

 

$

 

 

$

93

 

 

$

118

 

Investments in equity method unconsolidated affiliates

822

 

 

190

 

 

48

 

 

1,060

 

 

 

 

 

Total assets

$

822

 

 

$

190

 

 

$

48

 

 

$

1,060

 

 

$

93

 

 

$

118

 

Taxes accrued

(1

)

 

 

 

 

 

(1

)

 

 

 

 

Other current liabilities

 

 

 

 

4

 

 

4

 

 

 

 

 

Deferred income taxes

21

 

 

 

 

 

 

21

 

 

 

 

 

Other noncurrent liabilities

 

 

 

 

12

 

 

12

 

 

 

 

 

Total liabilities

$

20

 

 

$

 

 

$

16

 

 

$

36

 

 

$

 

 

$

 

Net assets

$

802

 

 

$

190

 

 

$

32

 

 

$

1,024

 

 

$

93

 

 

$

118

 

 

 

December 31, 2017

 

Duke Energy

 

Duke

 

Duke

 

Pipeline

 

Commercial

 

Other

 

 

 

Energy

 

Energy

(in millions)

Investments

 

Renewables

 

VIEs

 

Total

 

Ohio

 

Indiana

Receivables from affiliated companies

$

 

 

$

 

 

$

 

 

$

 

 

$

87

 

 

$

106

 

Investments in equity method unconsolidated affiliates

697

 

 

180

 

 

42

 

 

919

 

 

 

 

 

Other noncurrent assets

17

 

 

 

 

 

 

17

 

 

 

 

 

Total assets

$

714

 

 

$

180

 

 

$

42

 

 

$

936

 

 

$

87

 

 

$

106

 

Taxes accrued

(29

)

 

 

 

 

 

(29

)

 

 

 

 

Other current liabilities

 

 

 

 

4

 

 

4

 

 

 

 

 

Deferred income taxes

42

 

 

 

 

 

 

42

 

 

 

 

 

Other noncurrent liabilities

 

 

 

 

12

 

 

12

 

 

 

 

 

Total liabilities

$

13

 

 

$

 

 

$

16

 

 

$

29

 

 

$

 

 

$

 

Net assets

$

701

 

 

$

180

 

 

$

26

 

 

$

907

 

 

$

87

 

 

$

106

 

The Duke Energy Registrants are not aware of any situations where the maximum exposure to loss significantly exceeds the carrying values shown above except for the power purchase agreement with OVEC, which is discussed below, and various guarantees, including Duke Energy's guarantee agreement to support its share of the ACP revolving credit facility. Duke Energy's maximum exposure to loss under the terms of the guarantee is $677 million as of December 31, 2018. For more information on various guarantees, refer to Note 7.

 

 

Pipeline Investments

Duke Energy has investments in various joint ventures with pipeline projects currently under construction. These entities are considered VIEs due to having insufficient equity to finance their own activities without subordinated financial support. Duke Energy does not have the power to direct the activities that most significantly impact the economic performance, the obligation to absorb losses or the right to receive benefits of these VIEs and therefore does not consolidate these entities.

The table below presents Duke Energy's ownership interest and investment balance in these joint ventures.

 

 

 

Investment Amount (in millions)

 

Ownership

 

December 31,

 

December 31,

Entity Name

Interest

 

2018

 

2017

ACP

47

%

 

$

797

 

 

$

397

 

Sabal Trail(a)

7.5

%

 

 

 

219

 

Constitution(b)

24

%

 

25

 

 

81

 

Total

 

 

$

822

 

 

$

697

 

(a) At December 31, 2017, Sabal Trail was considered a VIE due to having insufficient equity to finance their own activities without subordinated financial support. However, Sabal Trail is now a fully operational, well capitalized entity. As a result, Sabal Trail has sufficient equity to finance its own activities, and therefore, is no longer considered a VIE. Duke Energy's investment in Sabal Trail was $112 million at December 31, 2018.

(b) During the year ended December 31, 2018, Duke Energy recorded an OTTI of $55 million related to Constitution within Equity in earnings of unconsolidated affiliates on Duke Energy's Consolidated Statements of Income. See Note 4 for additional information.

 

Commercial Renewables

Duke Energy has investments in various renewable energy project entities. Some of these entities are VIEs due to Duke Energy issuing guarantees for debt service and operations and maintenance reserves in support of debt financings. Duke Energy does not consolidate these VIEs because power to direct and control key activities is shared jointly by Duke Energy and other owners.

Pioneer

Duke Energy holds a 50 percent equity interest in Pioneer. Pioneer is considered a VIE due to having insufficient equity to finance their own activities without subordinated financial support. The activities that most significantly impact Pioneer's economic performance are decisions related to the development of new transmission facilities. The power to direct these activities is jointly and equally shared by Duke Energy and the other joint venture partner, American Electric Power; therefore, Duke Energy does not consolidate Pioneer.

OVEC

Duke Energy Ohio’s 9 percent ownership interest in OVEC is considered a non-consolidated VIE due to having insufficient equity to finance its activities without subordinated financial support. The activities that most significantly impact OVEC's economic performance include fuel strategy and supply activities and decisions associated with ongoing operations and maintenance-related activities. Duke Energy Ohio does not have the unilateral power to direct these activities, and therefore, does not consolidate OVEC.

As a counterparty to an ICPA, Duke Energy Ohio has a contractual arrangement to receive entitlements to capacity and energy from OVEC’s power plants through June 2040 commensurate with its power participation ratio, which is equivalent to Duke Energy Ohio's ownership interest. Costs, including fuel, operating expenses, fixed costs, debt amortization, and interest expense, are allocated to counterparties to the ICPA based on their power participation ratio. The value of the ICPA is subject to variability due to fluctuation in power prices and changes in OVEC's cost of business. On March 31, 2018, FES, a subsidiary of FirstEnergy and an ICPA counterparty with a power participation ratio of 4.85 percent, filed for Chapter 11 bankruptcy, which could increase costs allocated to the counterparties. On July 31, 2018, the bankruptcy court rejected the FES ICPA, which means OVEC is an unsecured creditor in the FES bankruptcy proceeding. Duke Energy Ohio cannot predict the impact of the bankruptcy filing on its OVEC interests. In addition, certain proposed environmental rulemaking could result in future increased OVEC cost allocations. See Note 4 for additional information.

 

CRC

See discussion under Consolidated VIEs for additional information related to CRC.

Amounts included in Receivables from affiliated companies in the above table for Duke Energy Ohio and Duke Energy Indiana reflect their retained interest in receivables sold to CRC. These subordinated notes held by Duke Energy Ohio and Duke Energy Indiana are stated at fair value. Carrying values of retained interests are determined by allocating carrying value of the receivables between assets sold and interests retained based on relative fair value. The allocated bases of the subordinated notes are not materially different than their face value because (i) the receivables generally turnover in less than two months, (ii) credit losses are reasonably predictable due to the broad customer base and lack of significant concentration and (iii) the equity in CRC is subordinate to all retained interests and thus would absorb losses first. The hypothetical effect on fair value of the retained interests assuming both a 10 percent and a 20 percent unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history. Interest accrues to Duke Energy Ohio and Duke Energy Indiana on the retained interests using the acceptable yield method. This method generally approximates the stated rate on the notes since the allocated basis and the face value are nearly equivalent. An impairment charge is recorded against the carrying value of both retained interests and purchased beneficial interest whenever it is determined that an OTTI has occurred.

Key assumptions used in estimating fair value are detailed in the following table.

 

Duke Energy Ohio

 

Duke Energy Indiana

 

2018

 

2017

 

2018

 

2017

Anticipated credit loss ratio

0.5

%

 

0.5

%

 

0.3

%

 

0.3

%

Discount rate

3.0

%

 

2.1

%

 

3.0

%

 

2.1

%

Receivable turnover rate

13.5

%

 

13.5

%

 

11.0

%

 

10.7

%

The following table shows the gross and net receivables sold.

 

Duke Energy Ohio

 

Duke Energy Indiana

(in millions)

2018

 

2017

 

2018

 

2017

Receivables sold

$

269

 

 

$

273

 

 

$

336

 

 

$

312

 

Less: Retained interests

93

 

 

87

 

 

118

 

 

106

 

Net receivables sold

$

176

 

 

$

186

 

 

$

218

 

 

$

206

 

The following table shows sales and cash flows related to receivables sold.

 

Duke Energy Ohio

 

Duke Energy Indiana

 

Years Ended December 31,

 

Years Ended December 31,

(in millions)

2018

 

2017

 

2016

 

2018

 

2017

 

2016

Sales

 

 

 

 

 

 

 

 

 

 

 

Receivables sold

$

1,987

 

 

$

1,879

 

 

$

1,926

 

 

$

2,842

 

 

$

2,711

 

 

$

2,635

 

Loss recognized on sale

13

 

 

10

 

 

9

 

 

16

 

 

12

 

 

11

 

Cash Flows

 

 

 

 

 

 

 

 

 

 

 

Cash proceeds from receivables sold

1,967

 

 

1,865

 

 

1,882

 

 

2,815

 

 

2,694

 

 

2,583

 

Collection fees received

1

 

 

1

 

 

1

 

 

1

 

 

1

 

 

1

 

Return received on retained interests

6

 

 

3

 

 

2

 

 

9

 

 

7

 

 

5

 

Cash flows from the sales of receivables are reflected within Cash Flows From Operating Activities on Duke Energy Ohio’s and Duke Energy Indiana’s Consolidated Statements of Cash Flows.

Collection fees received in connection with servicing transferred accounts receivable are included in Operation, maintenance and other on Duke Energy Ohio’s and Duke Energy Indiana’s Consolidated Statements of Operations and Comprehensive Income. The loss recognized on sales of receivables is calculated monthly by multiplying receivables sold during the month by the required discount. The required discount is derived monthly utilizing a three-year weighted average formula that considers charge-off history, late charge history and turnover history on the sold receivables, as well as a component for the time value of money. The discount rate, or component for the time value of money, is the prior month-end LIBOR plus a fixed rate of 1.00 percent.

 

18. REVENUE

As described in Note 1, Duke Energy adopted Revenue from Contracts with Customers effective January 1, 2018, using the modified retrospective method of adoption, which does not require restatement of prior year reported results. No cumulative effect adjustment was recorded as the vast majority of Duke Energy’s revenues are at-will and without a defined contractual term. Additionally, comparative disclosures for 2018 operating results with the previous revenue recognition rules are not applicable as Duke Energy’s revenue recognition has not materially changed as a result of the new standard.

Duke Energy recognizes revenue consistent with amounts billed under tariff offerings or at contractually agreed upon rates based on actual physical delivery of electric or natural gas service, including estimated volumes delivered when billings have not yet occurred. As such, the majority of Duke Energy’s revenues have fixed pricing based on the contractual terms of the published tariffs, with variability in expected cash flows attributable to the customer’s volumetric demand and ultimate quantities of energy or natural gas supplied and used during the billing period. The stand-alone selling price of related sales are designed to support recovery of prudently incurred costs and an appropriate return on invested assets and are primarily governed by published tariff rates or contractual agreements approved by relevant regulatory bodies. As described in Note 1, certain excise taxes and franchise fees levied by state or local governments are required to be paid even if not collected from the customer. These taxes are recognized on a gross basis as part of revenues. Duke Energy elects to account for all other taxes net of revenues.

Performance obligations are satisfied over time as energy or natural gas is delivered and consumed with billings generally occurring monthly and related payments due within 30 days, depending on regulatory requirements. In no event does the timing between payment and delivery of the goods and services exceed one year. Using this output method for revenue recognition provides a faithful depiction of the transfer of electric and natural gas service as customers obtain control of the commodity and benefit from its use at delivery. Additionally, Duke Energy has an enforceable right to consideration for energy or natural gas delivered at any discrete point in time, and will recognize revenue at an amount that reflects the consideration to which Duke Energy is entitled for the energy or natural gas delivered.

As described above, the majority of Duke Energy’s tariff revenues are at-will and, as such, related contracts with customers have an expected duration of one year or less and will not have future performance obligations for disclosure. Additionally, other long-term revenue streams, including wholesale contracts, generally provide services that are part of a single performance obligation, the delivery of electricity or natural gas. As such, other than material fixed consideration under long-term contracts, related disclosures for future performance obligations are also not applicable.

Duke Energy earns substantially all of its revenues through its reportable segments, Electric Utilities and Infrastructure, Gas Utilities and Infrastructure and Commercial Renewables.

Electric Utilities and Infrastructure

Electric Utilities and Infrastructure earns the majority of its revenues through retail and wholesale electric service through the generation, transmission, distribution and sale of electricity. Duke Energy generally provides retail and wholesale electric service customers with their full electric load requirements or with supplemental load requirements when the customer has other sources of electricity.

Retail electric service is generally marketed throughout Duke Energy's electric service territory through standard service offers. The standard service offers are through tariffs determined by regulators in Duke Energy's regulated service territory. Each tariff, which is assigned to customers based on customer class, has multiple components such as an energy charge, a demand charge, a basic facilities charge and applicable riders. Duke Energy considers each of these components to be aggregated into a single performance obligation for providing electric service, or in the case of distribution only customers in Duke Energy Ohio, for delivering electricity. Electricity is considered a single performance obligation satisfied over time consistent with the series guidance and is provided and consumed over the billing period, generally one month. Retail electric service is typically provided to at-will customers who can cancel service at any time, without a substantive penalty. Additionally, Duke Energy adheres to applicable regulatory requirements in each jurisdiction to ensure the collectability of amounts billed and appropriate mitigating procedures are followed when necessary. As such, revenue from contracts with customers for such contracts is equivalent to the electricity supplied and billed in that period (including unbilled estimates).

Wholesale electric service is generally provided under long-term contracts using cost-based pricing. FERC regulates costs that may be recovered from customers and the amount of return companies are permitted to earn. Wholesale contracts include both energy and demand charges. For full requirements contracts, Duke Energy considers both charges as a single performance obligation for providing integrated electric service. For contracts where energy and demand charges are considered separate performance obligations, energy and demand are each a distinct performance obligation under the series guidance and are satisfied as energy is delivered and stand-ready service is provided on a monthly basis. This service represents consumption over the billing period and revenue is recognized consistent with billings and unbilled estimates, which generally occur monthly. Contractual amounts owed are typically trued up annually based upon incurred costs in accordance with FERC published filings and the specific customer’s actual peak demand. Estimates of variable consideration related to potential additional billings or refunds owed are updated quarterly.

The majority of wholesale revenues are full requirements contracts where the customers purchase the substantial majority of their energy needs and do not have a fixed quantity of contractually required energy or capacity. As such, related forecasted revenues are considered optional purchases. Supplemental requirements contracts that include contracted blocks of energy and capacity at contractually fixed prices have the following estimated remaining performance obligations:

 

Remaining Performance Obligations

(in millions)

2019

2020

2021

2022

2023

Thereafter

Total

Progress Energy

$

112

 

$

121

 

$

80

 

$

82

 

$

39

 

$

42

 

$

476

 

Duke Energy Progress

9

 

9

 

9

 

9

 

9

 

9

 

54

 

Duke Energy Florida

103

 

112

 

71

 

73

 

30

 

33

 

422

 

Duke Energy Indiana

9

 

10

 

5

 

 

 

 

24

 

Revenues for block sales are recognized monthly as energy is delivered and stand-ready service is provided, consistent with invoiced amounts and unbilled estimates.

Gas Utilities and Infrastructure

Gas Utilities and Infrastructure earns its revenue through retail and wholesale natural gas service through the transportation, distribution and sale of natural gas. Duke Energy generally provides retail and wholesale natural gas service customers with all natural gas load requirements. Additionally, while natural gas can be stored, substantially all natural gas provided by Duke Energy is consumed by customers simultaneously with receipt of delivery.

Retail natural gas service is marketed throughout Duke Energy's natural gas service territory using published tariff rates. The tariff rates are established by regulators in Duke Energy's service territories. Each tariff, which is assigned to customers based on customer class, have multiple components, such as a commodity charge, demand charge, customer or monthly charge and transportation costs. Duke Energy considers each of these components to be aggregated into a single performance obligation for providing natural gas service. For contracts where Duke Energy provides all of the customer’s natural gas needs, the delivery of natural gas is considered a single performance obligation satisfied over time, and revenue is recognized monthly based on billings and unbilled estimates as service is provided and the commodity is consumed over the billing period. Additionally, natural gas service is typically at-will and customers can cancel service at any time, without a substantive penalty. Duke Energy also adheres to applicable regulatory requirements to ensure the collectability of amounts billed and receivable and appropriate mitigating procedures are followed when necessary.

Certain long-term individually negotiated contracts exist to provide natural gas service. These contracts are regulated and approved by state commissions. The negotiated contracts have multiple components, including a natural gas and a demand charge, similar to retail natural gas contracts. Duke Energy considers each of these components to be a single performance obligation for providing natural gas service. This service represents consumption over the billing period, generally one month.

Fixed capacity payments under long-term contracts for the Gas Utilities and Infrastructure segment include minimum margin contracts and supply arrangements with municipalities and power generation facilities. Revenues for related sales are recognized monthly as natural gas is delivered and stand-ready service is provided, consistent with invoiced amounts and unbilled estimates. Estimated remaining performance obligations are as follows:

 

Remaining Performance Obligations

(in millions)

2019

2020

2021

2022

2023

Thereafter

Total

Piedmont

$

70

 

$

68

 

$

63

 

$

63

 

$

60

 

$

430

 

$

754

 

Commercial Renewables

Commercial Renewables earns the majority of its revenues through long-term PPAs and generally sells all of its wind and solar facility output, electricity and RECs to customers. The majority of these PPAs have historically been accounted for as leases. For PPAs that are not accounted for as leases, the delivery of electricity and the delivery of RECs are considered separate performance obligations.

The delivery of electricity is a performance obligation satisfied over time and represents generation and consumption of the electricity over the billing period, generally one month. The delivery of RECs is a performance obligation satisfied at a point in time and represents delivery of each REC generated by the wind or solar facility. The majority of self-generated RECs are bundled with energy in Duke Energy’s contracts and, as such, related revenues are recognized as energy is generated and delivered as that pattern is consistent with Duke Energy’s performance. Commercial Renewables recognizes revenue based on the energy generated and billed for the period, generally one month, at contractual rates (including unbilled estimates) according to the invoice practical expedient. Amounts are typically due within 30 days of invoice.

Commercial Renewables also earns revenues from installation of distributed solar generation resources, which is primarily composed of EPC projects to deliver functioning solar power systems, generally completed within two to 12 months from commencement of construction. The installation of distributed solar generation resources is a performance obligation that is satisfied over time. Revenue from fixed-price EPC contracts is recognized using the input method as work is performed based on the estimated ratio of incurred costs to estimated total costs.

Other

The remainder of Duke Energy’s operations is presented as Other, which does not include material revenues from contracts with customers.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Disaggregated Revenues

For the Electric and Gas Utility and Infrastructure segments, revenue by customer class is most meaningful to Duke Energy as each respective customer class collectively represents unique customer expectations of service, generally has different energy and demand requirements, and operates under tailored, regulatory approved pricing structures. Additionally, each customer class is impacted differently by weather and a variety of economic factors including the level of population growth, economic investment, employment levels, and regulatory activities in each of Duke Energy’s jurisdictions. As such, analyzing revenues disaggregated by customer class allows Duke Energy to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For the Commercial Renewables segment, the majority of revenues from contracts with customers are from selling all of the unit-contingent output at contractually defined pricing under long-term PPAs with consistent expectations regarding the timing and certainty of cash flows. Disaggregated revenues are presented as follows:

 

Year Ended December 31, 2018

 

 

Duke

 

Duke

Duke

Duke

Duke

 

(in millions)

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

By market or type of customer

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Electric Utilities and Infrastructure

 

 

 

 

 

 

 

 

Residential

$

9,587

 

$

2,981

 

$

4,785

 

$

2,019

 

$

2,766

 

$

743

 

$

1,076

 

$

 

General

6,127

 

2,119

 

2,809

 

1,280

 

1,529

 

422

 

778

 

 

Industrial

2,974

 

1,180

 

904

 

642

 

262

 

131

 

760

 

 

Wholesale

2,324

 

508

 

1,462

 

1,303

 

159

 

57

 

298

 

 

Other revenues

717

 

320

 

502

 

320

 

182

 

73

 

91

 

 

Total Electric Utilities and Infrastructure revenue from contracts with customers

$

21,729

 

$

7,108

 

$

10,462

 

$

5,564

 

$

4,898

 

$

1,426

 

$

3,003

 

$

 

 

 

 

 

 

 

 

 

 

Gas Utilities and Infrastructure

 

 

 

 

 

 

 

 

Residential

$

1,000

 

$

 

$

 

$

 

$

 

$

331

 

$

 

$

669

 

Commercial

514

 

 

 

 

 

135

 

 

378

 

Industrial

147

 

 

 

 

 

18

 

 

128

 

Power Generation

 

 

 

 

 

 

 

54

 

Other revenues

139

 

 

 

 

 

19

 

 

120

 

Total Gas Utilities and Infrastructure revenue from contracts with customers

$

1,800

 

$

 

$

 

$

 

$

 

$

503

 

$

 

$

1,349

 

 

 

 

 

 

 

 

 

 

Commercial Renewables

 

 

 

 

 

 

 

 

Revenue from contracts with customers

$

209

 

$

 

$

 

$

 

$

 

$

 

$

 

$

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

 

 

 

Revenue from contracts with customers

$

19

 

$

 

$

 

$

 

$

 

$

1

 

$

 

$

 

 

 

 

 

 

 

 

 

 

Total revenue from contracts with customers

$

23,757

 

$

7,108

 

$

10,462

 

$

5,564

 

$

4,898

 

$

1,930

 

$

3,003

 

$

1,349

 

 

 

 

 

 

 

 

 

 

Other revenue sources(a)

$

764

 

$

192

 

$

266

 

$

135

 

$

123

 

$

27

 

$

56

 

$

26

Total revenues

$

24,521

 

$

7,300

 

$

10,728

 

$

5,699

 

$

5,021

 

$

1,957

 

$

3,059

 

$

1,375

 

(a) Other revenue sources include revenues from leases, derivatives and alternative revenue programs that are not considered revenues from contracts with customers. Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over or under collection of related revenues.

IMPACT OF WEATHER AND THE TIMING OF BILLING PERIODS

Revenues and costs are influenced by seasonal weather patterns. Peak sales of electricity occur during the summer and winter months, which results in higher revenue and cash flows during these periods. By contrast, lower sales of electricity occur during the spring and fall, allowing for scheduled plant maintenance. Residential and general service customers are more impacted by weather than industrial customers. Estimated weather impacts are based on actual current period weather compared to normal weather conditions. Normal weather conditions are defined as the long-term average of actual historical weather conditions. Heating-degree days measure the variation in weather based on the extent the average daily temperature falls below a base temperature. Cooling-degree days measure the variation in weather based on the extent the average daily temperature rises above the base temperature. Each degree of temperature below the base temperature counts as one heating-degree day and each degree of temperature above the base temperature counts as one cooling-degree day.

The estimated impact of weather on earnings for Electric Utilities and Infrastructure is based on the temperature variances from a normal condition and customers' historic usage patterns. The methodology used to estimate the impact of weather does not consider all variables that may impact customer response to weather conditions, such as humidity in the summer or wind chill in the winter. The precision of this estimate may also be impacted by applying long-term weather trends to shorter-term periods.

Gas Utilities and Infrastructure's costs and revenues are influenced by seasonal patterns due to peak natural gas sales occurring during the winter months as a result of space heating requirements. Residential customers are the most impacted by weather. There are certain regulatory mechanisms for the North Carolina, South Carolina, Tennessee and Ohio service territories that normalize the margins collected from certain customer classes during the winter. In North Carolina, rate design provides protection from both weather and other usage variations such as conservation, while South Carolina and Tennessee revenues are adjusted solely based on weather. Ohio primarily employs a fixed charge each month regardless of the season and usage.

UNBILLED REVENUE

Unbilled revenues are recognized by applying customer billing rates to the estimated volumes of energy or natural gas delivered but not yet billed. Unbilled revenues can vary significantly from period to period as a result of seasonality, weather, customer usage patterns, customer mix, average price in effect for customer classes, timing of rendering customer bills and meter reading schedules, and the impact of weather normalization or margin decoupling mechanisms.

Unbilled revenues are included within Receivables and Receivables of VIEs on the Consolidated Balance Sheets as shown in the following table.

 

December 31,

(in millions)

2018

 

2017

Duke Energy

$

896

 

 

$

944

 

Duke Energy Carolinas

313

 

 

342

 

Progress Energy

244

 

 

228

 

Duke Energy Progress

148

 

 

143

 

Duke Energy Florida

96

 

 

85

 

Duke Energy Ohio

2

 

 

4

 

Duke Energy Indiana

23

 

 

21

 

Piedmont

73

 

 

86

 

Additionally, Duke Energy Ohio and Duke Energy Indiana sell, on a revolving basis, nearly all of their retail accounts receivable, including receivables for unbilled revenues, to an affiliate, CRC and accounts for the transfers of receivables as sales. Accordingly, the receivables sold are not reflected on the Consolidated Balance Sheets of Duke Energy Ohio and Duke Energy Indiana. See Note 17 for further information. These receivables for unbilled revenues are shown in the table below.

 

December 31,

(in millions)

2018

 

2017

Duke Energy Ohio

$

86

 

 

$

104

 

Duke Energy Indiana

128

 

 

132

 

 

19. COMMON STOCK

Basic EPS is computed by dividing net income attributable to Duke Energy common stockholders, as adjusted for distributed and undistributed earnings allocated to participating securities, by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income attributable to Duke Energy common stockholders, as adjusted for distributed and undistributed earnings allocated to participating securities, by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common shares, such as stock options and equity forward sale agreements, were exercised or settled. Duke Energy’s participating securities are restricted stock units that are entitled to dividends declared on Duke Energy common stock during the restricted stock unit’s vesting periods.

The following table presents Duke Energy’s basic and diluted EPS calculations and reconciles the weighted average number of common stock outstanding to the diluted weighted average number of common stock outstanding.

 

Years Ended December 31,

(in millions, except per share amounts)

2018

 

2017

 

2016

Income from continuing operations attributable to Duke Energy common stockholders excluding impact of participating securities

$

2,642

 

 

$

3,059

 

 

$

2,567

 

Weighted average shares outstanding – basic

708

 

 

700

 

 

691

 

Weighted average shares outstanding – diluted

708

 

 

700

 

 

691

 

Earnings per share from continuing operations attributable to Duke Energy common stockholders

 

 

 

 

 

Basic

$

3.73

 

 

$

4.37

 

 

$

3.71

 

Diluted

$

3.73

 

 

$

4.37

 

 

$

3.71

 

Potentially dilutive items excluded from the calculation(a)

2

 

 

2

 

 

2

 

Dividends declared per common share

$

3.64

 

 

$

3.49

 

 

$

3.36

 

(a) Performance stock awards were not included in the dilutive securities calculation because the performance measures related to the awards had not been met.

Equity Issuances

On February 20, 2018, Duke Energy filed a prospectus supplement and executed an EDA under which it may sell up to $1 billion of its common stock through an ATM offering program, including an equity forward sales component. The EDA was entered into with Wells Fargo Securities, LLC, Citigroup Global Markets Inc., and J.P. Morgan Securities LLC (the Agents). Under the terms of the EDA, Duke Energy may issue and sell, through any of the Agents, shares of common stock during the period ending September 23, 2019. In June 2018, Duke Energy marketed two separate tranches, each for 1.3 million shares, of common stock. The first tranche was marketed with Wells Fargo Bank at an initial forward price of $72.02 per share and the second tranche was marketed with Citibank at an initial forward price of $78.71 per share through equity forward transactions under the ATM program. The Equity Forwards require Duke Energy to either physically settle the transactions by issuing 2.6 million shares in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or net settle in whole or in part through the delivery or receipt of cash or shares. The settlement alternative was at Duke Energy's election. In December 2018, Duke Energy physically settled these equity forwards by delivering 2.6 million shares of common stock in exchange for net proceeds of approximately $195 million.

Separately, in March 2018, Duke Energy marketed an equity offering of 21.3 million shares of common stock through an Underwriting Agreement with Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Barclays Capital Inc. and Goldman Sachs & Co. LLC, as representatives of several underwriters, Credit Suisse Capital LLC and J.P. Morgan Securities LLC as Forward Sellers, and Credit Suisse Capital LLC and J.P. Morgan Chase Bank, National Association, acting as forward purchasers. In connection with the offering, Duke Energy entered into equity forward sale agreements with Credit Suisse Securities (USA) LLC as Agent for Credit Suisse Capital LLC and J.P. Morgan Chase Bank, National Association. The sale price was $75 per share less certain net adjustments for an initial forward price of $74.07 per share. The Equity Forwards require Duke Energy to either physically settle the transactions by issuing 21.3 million shares in exchange for net proceeds at the then-applicable forward sale price specified by the agreements, or net settle in whole or in part through the delivery or receipt of cash or shares. The settlement alternative was at Duke Energy's election. In June 2018, Duke Energy physically settled one-half of the equity forwards by delivering approximately 10.6 million shares of common stock in exchange for net cash proceeds of approximately $781 million. In December 2018, Duke Energy physically settled the remaining equity forward by delivering 10.6 million shares of common stock in exchange for net cash proceeds of approximately $766 million.

For the year ended December 31, 2018, Duke Energy issued 2.2 million shares through its DRIP with an increase in additional paid-in capital of approximately $174 million.

In March 2016, Duke Energy marketed an equity offering of 10.6 million shares of common stock. In lieu of issuing equity at the time of the offering, Duke Energy entered into Equity Forwards with Barclays. The Equity Forwards required Duke Energy to either physically settle the transactions by issuing 10.6 million shares, or net settle in whole or in part through the delivery or receipt of cash or shares. On October 5, 2016, following the close of the Piedmont acquisition, Duke Energy physically settled the Equity Forwards in full by delivering 10.6 million shares of common stock in exchange for net cash proceeds of approximately $723 million. The net proceeds were used to finance a portion of the Piedmont acquisition. As a result of the acquisition, all of Piedmont's issued and outstanding stock became the issued and outstanding shares of a wholly owned subsidiary of Duke Energy. See Note 2 for additional information related to the Piedmont acquisition.

 

20. SEVERANCE

During 2018, Duke Energy reviewed its operations and identified opportunities for improvement to better serve its customers. This operational review included the company's workforce strategy and staffing levels to ensure the company is staffed with the right skillsets and number of teammates to execute the long-term vision for Duke Energy. As such, Duke Energy extended voluntary and involuntary severance benefits to certain employees in specific areas as a part of workforce planning and digital transformation efforts.

During 2016, Duke Energy and Piedmont announced severance plans covering certain eligible employees whose employment will be involuntarily terminated without cause as a result of Duke Energy's acquisition of Piedmont. These reductions continued into 2017 and were a part of the synergies expected to be realized with the acquisition. Refer to Note 2 for additional information on the Piedmont acquisition.

Severance benefit charges for initiatives and plans discussed above were accrued for a total of approximately 1,900 employees in 2018, 100 employees in 2017 and 600 employees in 2016. The following table presents the direct and allocated severance and related charges recorded by the Duke Energy Registrants. Amounts are included within Operation, maintenance and other on the Consolidated Statements of Operations.

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont(a)

Year Ended December 31, 2018

$

187

 

$

102

 

$

69

 

$

52

 

$

17

 

$

6

 

$

7

 

$

2

 

Year Ended December 31, 2017

15

 

2

 

2

 

1

 

1

 

 

1

 

9

Year Ended December 31, 2016

118

 

39

 

40

 

23

 

17

 

3

 

7

 

 

(a) Piedmont severance benefit charges were $3 million for the two months ended December 31, 2016, and $19 million for the year ended October 31, 2016.

 

 

 

 

The table below presents the severance liability for past and ongoing severance plans including the plans described above.

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Balance at December 31, 2017

$

19

 

$

5

 

$

2

 

$

1

 

$

 

$

 

$

 

$

5

 

Provision/Adjustments

200

 

98

 

50

 

40

 

10

 

2

 

2

 

 

Cash Reductions

(14

)

(3

)

(1

)

 

(1

)

 

 

(5

)

Balance at December 31, 2018

$

205

 

$

100

 

$

51

 

$

41

 

$

9

 

$

2

 

$

2

 

$

 

 

21. STOCK-BASED COMPENSATION

The 2015 Plan provides for the grant of stock-based compensation awards to employees and outside directors. The 2015 Plan reserves 10 million shares of common stock for issuance. Duke Energy has historically issued new shares upon exercising or vesting of share-based awards. However, Duke Energy may use a combination of new share issuances and open market repurchases for share-based awards that are exercised or vest in the future. Duke Energy has not determined with certainty the amount of such new share issuances or open market repurchases.

The following table summarizes the total expense recognized by the Duke Energy Registrants, net of tax, for stock-based compensation.

 

Years Ended December 31,

(in millions)

2018

 

2017

 

2016

Duke Energy

$

56

 

 

$

43

 

 

$

35

 

Duke Energy Carolinas

20

 

 

15

 

 

12

 

Progress Energy

21

 

 

16

 

 

12

 

Duke Energy Progress

13

 

 

10

 

 

7

 

Duke Energy Florida

8

 

 

6

 

 

5

 

Duke Energy Ohio

4

 

 

3

 

 

2

 

Duke Energy Indiana

5

 

 

4

 

 

3

 

Piedmont(a)

3

 

 

3

 

 

 

(a) Piedmont's stock-based compensation costs were not material for the two months ended December 31, 2016. See discussion below for information on Piedmont's pre-merger stock-based compensation plans.

Duke Energy's pretax stock-based compensation costs, the tax benefit associated with stock-based compensation expense and stock-based compensation costs capitalized are included in the following table.

 

Years Ended December 31,

(in millions)

2018

 

2017

 

2016

Restricted stock unit awards

$

43

 

 

$

41

 

 

$

36

 

Performance awards

35

 

 

27

 

 

19

 

Pretax stock-based compensation cost

$

78

 

 

$

68

 

 

$

55

 

Stock-based compensation costs capitalized

5

 

 

4

 

 

2

 

Stock-based compensation expense

$

73

 

 

$

64

 

 

$

53

 

Tax benefit associated with stock-based compensation expense

$

17

 

 

$

25

 

 

$

20

 

 

RESTRICTED STOCK UNIT AWARDS

RSU awards generally vest over periods from immediate to three years. Fair value amounts are based on the market price of Duke Energy's common stock on the grant date. The following table includes information related to RSU awards.

 

Years Ended December 31,

 

2018

 

2017

 

2016

Shares awarded (in thousands)

649

 

 

583

 

 

684

 

Fair value (in millions)

$

49

 

 

$

47

 

 

$

52

 

The following table summarizes information about RSU awards outstanding.

 

 

 

Weighted Average

 

Shares

 

Grant Date Fair Value

 

(in thousands)

 

(per share)

Outstanding at December 31, 2017

1,121

 

 

$

78

 

Granted

649

 

 

76

 

Vested

(545

)

 

78

 

Forfeited

(72

)

 

77

 

Outstanding at December 31, 2018

1,153

 

 

77

 

Restricted stock unit awards expected to vest

1,101

 

 

77

 

The total grant date fair value of shares vested during the years ended December 31, 2018, 2017 and 2016, was $43 million, $42 million and $38 million, respectively. At December 31, 2018, Duke Energy had $29 million of unrecognized compensation cost, which is expected to be recognized over a weighted average period of 23 months.

PERFORMANCE AWARDS

Stock-based performance awards generally vest after three years if performance targets are met. The actual number of shares issued will range from zero to 200 percent of target shares, depending on the level of performance achieved.

Performance awards contain market conditions based on relative TSR compared to a predefined peer group, as well as a performance condition based on Duke Energy's cumulative adjusted EPS. Performance awards granted in 2018 and 2017 also contain a performance condition based on the total incident case rate, one of our key employee safety metrics.

The market condition component of Duke Energy's performance awards is valued using a path-dependent model that incorporates expected relative TSR into the fair value determination of Duke Energy’s performance-based share awards. The model uses three-year historical volatilities and correlations for all companies in the predefined peer group, including Duke Energy, to simulate Duke Energy’s relative TSR as of the end of the performance period. For each simulation, Duke Energy’s relative TSR associated with the simulated stock price at the end of the performance period plus expected dividends within the period results in a value per share for the award portfolio. The average of these simulations is the expected portfolio value per share. Actual life to date results of Duke Energy’s relative TSR for each grant are incorporated within the model. For performance awards granted in 2018, the model used a risk-free interest rate of 2.4 percent, which reflects the yield on three-year Treasury bonds as of the grant date, and an expected volatility of 16.0 percent based on Duke Energy's historical volatility over three years using daily stock prices.

The following table includes information related to stock-based performance awards.

 

Years Ended December 31,

 

2018

 

2017

 

2016

Shares granted assuming target performance (in thousands)

372

 

 

461

 

 

338

 

Fair value (in millions)

$

27

 

 

$

37

 

 

$

25

 

 

The following table summarizes information about stock-based performance awards outstanding and assumes payout at the target level.

 

 

 

Weighted Average

 

Shares

 

Grant Date Fair Value

 

(in thousands)

 

(per share)

Outstanding at December 31, 2017

1,065

 

 

$

79

 

Granted

372

 

 

73

 

Vested

(155

)

 

81

 

Forfeited

(165

)

 

80

 

Outstanding at December 31, 2018

1,117

 

 

77

 

Stock-based performance awards expected to vest

1,086

 

 

77

 

The total grant date fair value of shares vested during the years ended December 31, 2018, and 2016, was $13 million and $25 million, respectively. No performance awards vested during the year ended December 31, 2017. At December 31, 2018, Duke Energy had $30 million of unrecognized compensation cost, which is expected to be recognized over a weighted average period of 21 months.

PIEDMONT

Prior to Duke Energy's acquisition of Piedmont, Piedmont had an incentive compensation plan that had a series of three-year performance and RSU awards for eligible officers and other participants. The Merger Agreement provided for the conversion of the 2014-2016 and 2015-2017 performance awards and the nonvested 2016 RSU award into the right to receive $60 cash per share upon the close of the transaction. In December 2015, Piedmont's board of directors authorized the accelerated vesting, payment and taxation of the 2014-2016 and 2015-2017 performance awards, as well as the 2016 RSU award, at the election of the participant. Substantially all participants elected to accelerate the settlement of these awards. As a result of the settlement of these awards, 194 thousand shares of Piedmont shares were issued to participants, net of shares withheld for applicable federal and state income taxes, at a closing price of $56.85 and a fair value of $11 million. The 2016-2018 performance award cycle was approved subsequent to the Merger Agreement and was converted into a Duke Energy RSU award at the consummation of the acquisition.

Piedmont's stock-based compensation costs and the tax benefit associated with stock-based compensation expense are included in the following table.

(in millions)

Year Ended October 31, 2016

Pretax stock-based compensation cost

$

16

 

Tax benefit associated with stock-based compensation expense

6

 

Net of tax stock-based compensation cost

$

10

 

 

22. EMPLOYEE BENEFIT PLANS

DEFINED BENEFIT RETIREMENT PLANS

Duke Energy and certain subsidiaries maintain, and the Subsidiary Registrants participate in, qualified, non-contributory defined benefit retirement plans. The Duke Energy plans cover most employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits based upon a percentage of current eligible earnings, age or age and years of service and interest credits. Certain employees are eligible for benefits that use a final average earnings formula. Under these final average earnings formulas, a plan participant accumulates a retirement benefit equal to the sum of percentages of their (i) highest three-year, four-year, or five-year average earnings, (ii) highest three-year, four-year, or five-year average earnings in excess of covered compensation per year of participation (maximum of 35 years) or (iii) highest three-year average earnings times years of participation in excess of 35 years. Duke Energy also maintains, and the Subsidiary Registrants participate in, non-qualified, non-contributory defined benefit retirement plans that cover certain executives. The qualified and non-qualified, non-contributory defined benefit plans are closed to new participants.

Duke Energy approved plan amendments to restructure its qualified non-contributory defined benefit retirement plans, effective January 1, 2018. The restructuring involved (i) the spin-off of the majority of inactive participants from two plans into a separate inactive plan and (ii) the merger of the active participant portions of such plans, along with a pension plan acquired as part of the Piedmont transaction, into a single active plan. Benefits offered to the plan participants remain unchanged except that the Piedmont plan's final average earnings formula was frozen as of December 31, 2017, and affected participants were moved into the active plan's cash balance formula. Actuarial gains and losses associated with the Inactive Plan will be amortized over the remaining life expectancy of the inactive participants. The longer amortization period lowered Duke Energy's 2018 pretax qualified pension plan expense by approximately $33 million.

Duke Energy uses a December 31 measurement date for its defined benefit retirement plan assets and obligations.

Net periodic benefit costs disclosed in the tables below represent the cost of the respective benefit plan for the periods presented prior to capitalization of amounts reflected as Net property, plant and equipment, on the Consolidated Balance Sheets. Only the service cost component of net periodic benefit costs is eligible to be capitalized. The remaining non-capitalized portions of net periodic benefit costs are classified as either: (1) service cost, which is recorded in Operations, maintenance and other on the Consolidated Statements of Operations; or as (2) components of non-service cost, which is recorded in Other income and expenses, net, on the Consolidated Statements of Operations. Amounts presented in the tables below for the Subsidiary Registrants represent the amounts of pension and other post-retirement benefit cost allocated by Duke Energy for employees of the Subsidiary Registrants. Additionally, the Consolidated Statements of Operations of the Subsidiary Registrants also include allocated net periodic benefit costs for their proportionate share of pension and post-retirement benefit cost for employees of Duke Energy’s shared services affiliate that provide support to the Subsidiary Registrants. However, in the tables below, these amounts are only presented within the Duke Energy column. These allocated amounts are included in the governance and shared service costs discussed in Note 13.

Duke Energy’s policy is to fund amounts on an actuarial basis to provide assets sufficient to meet benefit payments to be paid to plan participants. Duke Energy does not anticipate making any contributions in 2019. The following table includes information related to the Duke Energy Registrants’ contributions to its qualified defined benefit pension plans.

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont(a)

Contributions Made:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2018

$

141

 

 

$

46

 

 

$

45

 

 

$

25

 

 

$

20

 

 

$

 

 

$

8

 

 

$

 

2017

19

 

 

 

 

 

 

 

 

 

 

4

 

 

 

 

11

 

2016

155

 

 

43

 

 

43

 

 

24

 

 

20

 

 

5

 

 

9

 

 

 

(a) Piedmont contributed $10 million to its U.S. qualified defined benefit pension plan during the two months ended December 31, 2016, and $10 million for the year ended October 31, 2016.

 

 

 

 

 

 

 

 

 

 

QUALIFIED PENSION PLANS

Components of Net Periodic Pension Costs

 

Year Ended December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Service cost

$

182

 

 

$

58

 

 

$

51

 

 

$

29

 

 

$

22

 

 

$

5

 

 

$

11

 

 

$

7

 

Interest cost on projected benefit obligation

299

 

 

72

 

 

94

 

 

43

 

 

50

 

 

17

 

 

23

 

 

11

 

Expected return on plan assets

(559

)

 

(147

)

 

(178

)

 

(85

)

 

(91

)

 

(28

)

 

(42

)

 

(22

)

Amortization of actuarial loss

132

 

 

29

 

 

44

 

 

21

 

 

23

 

 

5

 

 

10

 

 

11

 

Amortization of prior service credit

(32

)

 

(8

)

 

(3

)

 

(2

)

 

(1

)

 

 

 

(2

)

 

(10

)

Net periodic pension costs(a)(b)

$

22

 

 

$

4

 

 

$

8

 

 

$

6

 

 

$

3

 

 

$

(1

)

 

$

 

 

$

(3

)

 

 

Year Ended December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Service cost

$

159

 

 

$

48

 

 

$

45

 

 

$

26

 

 

$

19

 

 

$

4

 

 

$

9

 

 

$

10

 

Interest cost on projected benefit obligation

328

 

 

79

 

 

100

 

 

47

 

 

53

 

 

18

 

 

26

 

 

14

 

Expected return on plan assets

(545

)

 

(142

)

 

(167

)

 

(82

)

 

(85

)

 

(27

)

 

(42

)

 

(24

)

Amortization of actuarial loss

146

 

 

31

 

 

52

 

 

23

 

 

29

 

 

5

 

 

12

 

 

11

 

Amortization of prior service credit

(24

)

 

(8

)

 

(3

)

 

(2

)

 

(1

)

 

(1

)

 

(2

)

 

(2

)

Settlement charge

12

 

 

 

 

 

 

 

 

 

 

 

 

 

 

12

 

Other

8

 

 

2

 

 

2

 

 

1

 

 

1

 

 

 

 

1

 

 

1

 

Net periodic pension costs(a)(b)

$

84

 

 

$

10

 

 

$

29

 

 

$

13

 

 

$

16

 

 

$

(1

)

 

$

4

 

 

$

22

 

 

 

Year Ended December 31, 2016

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

Service cost

$

147

 

 

$

48

 

 

$

42

 

 

$

24

 

 

$

19

 

 

$

4

 

 

$

9

 

Interest cost on projected benefit obligation

335

 

 

86

 

 

106

 

 

49

 

 

55

 

 

19

 

 

28

 

Expected return on plan assets

(519

)

 

(142

)

 

(168

)

 

(82

)

 

(84

)

 

(27

)

 

(42

)

Amortization of actuarial loss

134

 

 

33

 

 

51

 

 

23

 

 

29

 

 

4

 

 

11

 

Amortization of prior service credit

(17

)

 

(8

)

 

(3

)

 

(2

)

 

(1

)

 

 

 

(1

)

Settlement charge

3

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

8

 

 

2

 

 

3

 

 

1

 

 

1

 

 

1

 

 

1

 

Net periodic pension costs(a)(b)

$

91

 

 

$

19

 

 

$

31

 

 

$

13

 

 

$

19

 

 

$

1

 

 

$

6

(a) Duke Energy amounts exclude $5 million, $7 million and $8 million for the years ended December 2018, 2017 and 2016, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

(b) Duke Energy Ohio amounts exclude $2 million, $3 million and $4 million for the years ended December 2018, 2017 and 2016, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

 

Piedmont

 

Two Months Ended

 

Year Ended

(in millions)

December 31, 2016

 

October 31, 2016

Service cost

$

2

 

 

$

11

 

Interest cost on projected benefit obligation

2

 

 

9

 

Expected return on plan assets

(4

)

 

(24

)

Amortization of actuarial loss

2

 

 

8

 

Amortization of prior service credit

(1

)

 

(2

)

Settlement charge

3

 

 

 

Net periodic pension costs

$

4

 

 

$

2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts Recognized in Accumulated Other Comprehensive Income and Regulatory Assets

 

Year Ended December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Regulatory assets, net increase (decrease)

$

298

 

 

$

170

 

 

$

40

 

 

$

31

 

 

$

9

 

 

$

10

 

 

$

30

 

 

$

8

 

Accumulated other comprehensive loss (income)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred income tax expense

$

(2

)

 

 

 

1

 

 

 

 

 

 

 

 

 

 

 

Amortization of prior year service credit

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amortization of prior year actuarial losses

10

 

 

 

 

(4

)

 

 

 

 

 

 

 

 

 

 

Net amount recognized in accumulated other comprehensive income

$

9

 

 

$

 

 

$

(3

)

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

 

Year Ended December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Regulatory assets, net (decrease) increase

$

(212

)

 

$

(70

)

 

$

(49

)

 

$

(37

)

 

$

(11

)

 

$

9

 

 

$

(19

)

 

$

(64

)

Accumulated other comprehensive (income) loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred income tax expense

$

 

 

$

 

 

$

3

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Prior year service credit arising during the year

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amortization of prior year actuarial losses

(7

)

 

 

 

(7

)

 

 

 

 

 

 

 

 

 

 

Net amount recognized in accumulated other comprehensive income

$

(6

)

 

$

 

 

$

(4

)

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Piedmont's regulatory asset net increase was $34 million and $35 million for the two months ended December 31, 2016, and for the year ended October 31, 2016, respectively.

 

 

 

 

 

 

 

Reconciliation of Funded Status to Net Amount Recognized

 

Year Ended December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Change in Projected Benefit Obligation

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Obligation at prior measurement date

$

8,448

 

 

$

2,029

 

 

$

2,637

 

 

$

1,211

 

 

$

1,410

 

 

$

479

 

 

$

669

 

 

$

313

 

Service cost

174

 

 

56

 

 

49

 

 

28

 

 

21

 

 

5

 

 

10

 

 

7

 

Interest cost

299

 

 

72

 

 

94

 

 

43

 

 

50

 

 

17

 

 

23

 

 

11

 

Actuarial gain

(485

)

 

(44

)

 

(204

)

 

(87

)

 

(114

)

 

(29

)

 

(29

)

 

(18

)

Transfers

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(16

)

Benefits paid

(567

)

 

(159

)

 

(143

)

 

(70

)

 

(72

)

 

(37

)

 

(55

)

 

(33

)

Obligation at measurement date

$

7,869

 

 

$

1,954

 

 

$

2,433

 

 

$

1,125

 

 

$

1,295

 

 

$

435

 

 

$

618

 

 

$

264

 

Accumulated Benefit Obligation at measurement date

$

7,818

 

 

$

1,954

 

 

$

2,404

 

 

$

1,125

 

 

$

1,265

 

 

$

425

 

 

$

614

 

 

$

264

 

Change in Fair Value of Plan Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Plan assets at prior measurement date

$

9,003

 

 

$

2,372

 

 

$

2,814

 

 

$

1,366

 

 

$

1,429

 

 

$

458

 

 

$

684

 

 

$

368

 

Employer contributions

141

 

 

46

 

 

45

 

 

25

 

 

20

 

 

 

 

8

 

 

 

Actual return on plan assets

(344

)

 

(91

)

 

(110

)

 

(53

)

 

(55

)

 

(16

)

 

(26

)

 

(14

)

Benefits paid

(567

)

 

(159

)

 

(143

)

 

(70

)

 

(72

)

 

(37

)

 

(55

)

 

(33

)

Transfers

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(16

)

Plan assets at measurement date

$

8,233

 

 

$

2,168

 

 

$

2,606

 

 

$

1,268

 

 

$

1,322

 

 

$

405

 

 

$

611

 

 

$

305

 

Funded status of plan

$

364

 

 

$

214

 

 

$

173

 

 

$

143

 

 

$

27

 

 

$

(30

)

 

$

(7

)

 

$

41

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Change in Projected Benefit Obligation

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Obligation at prior measurement date

$

8,131

 

 

$

1,952

 

 

$

2,512

 

 

$

1,158

 

 

$

1,323

 

 

$

447

 

 

$

658

 

 

$

344

 

Service cost

159

 

 

48

 

 

45

 

 

26

 

 

19

 

 

4

 

 

9

 

 

10

 

Interest cost

328

 

 

79

 

 

100

 

 

47

 

 

53

 

 

18

 

 

26

 

 

14

 

Actuarial loss

455

 

 

68

 

 

158

 

 

57

 

 

99

 

 

35

 

 

26

 

 

38

 

Transfers

 

 

27

 

 

(32

)

 

(2

)

 

(15

)

 

12

 

 

 

 

 

Plan amendments

(61

)

 

 

 

 

 

 

 

 

 

 

 

 

 

(61

)

Benefits paid

(537

)

 

(145

)

 

(146

)

 

(75

)

 

(69

)

 

(37

)

 

(50

)

 

(5

)

Benefits paid — settlements

(27

)

 

 

 

 

 

 

 

 

 

 

 

 

 

(27

)

Obligation at measurement date

$

8,448

 

 

$

2,029

 

 

$

2,637

 

 

$

1,211

 

 

$

1,410

 

 

$

479

 

 

$

669

 

 

$

313

 

Accumulated Benefit Obligation at measurement date

$

8,369

 

 

$

2,029

 

 

$

2,601

 

 

$

1,211

 

 

$

1,375

 

 

$

468

 

 

$

652

 

 

$

313

 

Change in Fair Value of Plan Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Plan assets at prior measurement date

$

8,531

 

 

$

2,225

 

 

$

2,675

 

 

$

1,290

 

 

$

1,352

 

 

$

428

 

 

$

657

 

 

$

346

 

Employer contributions

19

 

 

 

 

 

 

 

 

 

 

4

 

 

 

 

11

 

Actual return on plan assets

1,017

 

 

265

 

 

317

 

 

153

 

 

161

 

 

51

 

 

77

 

 

43

Benefits paid

(537

)

 

(145

)

 

(146

)

 

(75

)

 

(69

)

 

(37

)

 

(50

)

 

(5

)

Benefits paid — settlements

(27

)

 

 

 

 

 

 

 

 

 

 

 

 

 

(27

)

Transfers

 

 

27

 

 

(32

)

 

(2

)

 

(15

)

 

12

 

 

 

 

 

Plan assets at measurement date

$

9,003

 

 

$

2,372

 

 

$

2,814

 

 

$

1,366

 

 

$

1,429

 

 

$

458

 

 

$

684

 

 

$

368

 

Funded status of plan

$

555

 

 

$

343

 

 

$

177

 

 

$

155

 

 

$

19

 

 

$

(21

)

 

$

15

 

 

$

55

 

 

 

 

 

 

 

 

 

Amounts Recognized in the Consolidated Balance Sheets

 

December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Prefunded pension(a)

$

433

 

 

$

214

 

 

$

242

 

 

$

143

 

 

$

96

 

 

$

24

 

 

$

39

 

 

$

41

 

Noncurrent pension liability(b)

$

69

 

 

$

 

 

$

69

 

 

$

 

 

$

69

 

 

$

54

 

 

$

46

 

 

$

 

Net asset (liability) recognized

$

364

 

 

$

214

 

 

$

173

 

 

$

143

 

 

$

27

 

 

$

(30

)

 

$

(7

)

 

$

41

 

Regulatory assets

$

2,184

 

 

$

576

 

 

$

796

 

 

$

372

 

 

$

424

 

 

$

100

 

 

$

182

 

 

$

81

 

Accumulated other comprehensive (income) loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred income tax benefit

$

(43

)

 

$

 

 

$

(2

)

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Prior service credit

(4

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net actuarial loss

126

 

 

 

 

5

 

 

 

 

 

 

 

 

 

 

 

Net amounts recognized in accumulated other comprehensive loss

$

79

 

 

$

 

 

$

3

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Amounts to be recognized in net periodic pension costs in the next year

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrecognized net actuarial loss

$

97

 

 

$

22

 

 

$

37

 

 

$

13

 

 

$

24

 

 

$

3

 

 

$

5

 

 

$

7

 

Unrecognized prior service credit

(32

)

 

(8

)

 

(3

)

 

(2

)

 

(1

)

 

 

 

(2

)

 

(9

)

 

 

December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Prefunded pension(a)

$

680

 

 

$

343

 

 

$

245

 

 

$

155

 

 

$

87

 

 

$

8

 

 

$

16

 

 

$

55

 

Noncurrent pension liability(b)

$

125

 

 

$

 

 

$

68

 

 

$

 

 

$

68

 

 

$

29

 

 

$

1

 

 

$

 

Net asset recognized

$

555

 

 

$

343

 

 

$

177

 

 

$

155

 

 

$

19

 

 

$

(21

)

 

$

15

 

 

$

55

 

Regulatory assets

$

1,886

 

 

$

406

 

 

$

756

 

 

$

341

 

 

$

415

 

 

$

90

 

 

$

152

 

 

$

73

 

Accumulated other comprehensive (income) loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred income tax benefit

$

(41

)

 

$

 

 

$

(3

)

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Prior service credit

(5

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net actuarial loss

116

 

 

 

 

9

 

 

 

 

 

 

 

 

 

 

 

Net amounts recognized in accumulated other comprehensive loss

$

70

 

 

$

 

 

$

6

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Amounts to be recognized in net periodic pension costs in the next year

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrecognized net actuarial loss

$

132

 

 

$

29

 

 

$

44

 

 

$

21

 

 

$

23

 

 

$

5

 

 

$

7

 

 

$

11

 

Unrecognized prior service credit

$

(32

)

 

$

(8

)

 

$

(3

)

 

$

(2

)

 

$

(1

)

 

$

 

 

$

(2

)

 

$

(9

)

(a) Included in Other within Other Noncurrent Assets on the Consolidated Balance Sheets.

(b) Included in Accrued pension and other post-retirement benefit costs on the Consolidated Balance Sheets.

Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets

 

December 31, 2018

 

 

 

Duke

Duke

Duke

 

Duke

Progress

Energy

Energy

Energy

(in millions)

Energy

Energy

Florida

Ohio

Indiana

Projected benefit obligation

$

679

 

$

679

 

$

679

 

$

123

 

$

203

 

Accumulated benefit obligation

651

 

651

 

651

 

115

 

199

 

Fair value of plan assets

610

 

610

 

610

 

69

 

159

 

 

 

December 31, 2017

 

 

 

Duke

Duke

 

Duke

Progress

Energy

Energy

(in millions)

Energy

Energy

Florida

Ohio

Projected benefit obligation

$

1,386

 

$

718

 

$

718

 

$

337

 

Accumulated benefit obligation

1,326

 

683

 

683

 

326

 

Fair value of plan assets

1,260

 

650

 

650

 

308

 

Assumptions Used for Pension Benefits Accounting

The discount rate used to determine the current year pension obligation and following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality corporate bonds that generate sufficient cash flow to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected.

The average remaining service period for participants in active plans and life expectancy of participants in inactive plans is 13 years for Duke Energy and Duke Energy Progress, 12 years for Duke Energy Carolinas, Progress Energy, and Duke Energy Florida, 14 years for Duke Energy Ohio and Duke Energy Indiana, and 10 years for Piedmont.

 

 

 

 

 

 

 

 

 

 

 

The following tables present the assumptions or range of assumptions used for pension benefit accounting.

 

 

December 31,

 

 

2018

 

2017

 

2016

Benefit Obligations

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

 

 

4.30%

 

 

 

3.60%

 

 

 

4.10%

Salary increase

 

3.50

%

4.00%

 

3.50

%

4.00%

 

4.00

%

4.50%

Net Periodic Benefit Cost

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

 

 

3.60%

 

 

 

4.10%

 

 

 

4.40%

Salary increase

 

3.50

%

4.00%

 

4.00

%

4.50%

 

4.00

%

4.40%

Expected long-term rate of return on plan assets

 

 

 

6.50%

 

6.50

%

6.75%

 

6.50

%

6.75%

 

 

 

Piedmont

 

 

Two Months Ended

 

Year Ended

 

 

December 31, 2016

 

October 31, 2016

Benefit Obligations

 

 

 

 

Discount rate

 

4.10

%

 

3.80

%

Salary increase

 

4.50

%

 

4.05

%

Net Periodic Benefit Cost

 

 

 

 

Discount rate

 

3.80

%

 

4.34

%

Salary increase

 

4.05

%

 

4.07

%

Expected long-term rate of return on plan assets

 

6.75

%

 

7.25

%

 

Expected Benefit Payments

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Years ending December 31,

 

 

 

 

 

 

 

 

2019

$

662

 

$

210

 

$

179

 

$

105

 

$

73

 

$

33

 

$

47

 

$

20

 

2020

651

 

177

 

171

 

90

 

80

 

37

 

51

 

24

 

2021

663

 

182

 

177

 

95

 

81

 

37

 

51

 

23

 

2022

662

 

189

 

179

 

94

 

84

 

37

 

49

 

22

 

2023

655

 

185

 

181

 

95

 

85

 

35

 

47

 

22

 

2024-2028

2,993

 

794

 

902

 

451

 

447

 

158

 

217

 

96

 

 

 

 

 

NON-QUALIFIED PENSION PLANS

Components of Net Periodic Pension Costs

 

Year Ended December 31, 2018

 

 

Duke

 

Duke

Duke

 

Duke

Energy

Progress

Energy

Energy

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Service cost

$

2

 

$

1

 

$

 

$

 

$

 

Interest cost on projected benefit obligation

12

 

 

4

 

1

 

2

 

Amortization of actuarial loss

8

 

 

2

 

1

 

1

 

Amortization of prior service credit

(2

)

 

 

 

 

Net periodic pension costs

$

20

 

$

1

 

$

6

 

$

2

 

$

3

 

 

 

Year Ended December 31, 2017

 

 

Duke

 

Duke

Duke

 

Duke

Energy

Progress

Energy

Energy

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Service cost

$

2

 

$

1

 

$

 

$

 

$

 

Interest cost on projected benefit obligation

13

 

1

 

5

 

1

 

2

 

Amortization of actuarial loss

8

 

 

2

 

1

 

1

 

Amortization of prior service credit

(2

)

 

 

 

 

Net periodic pension costs

$

21

 

$

2

 

$

7

 

$

2

 

$

3

 

 

 

Year Ended December 31, 2016

 

 

Duke

 

Duke

Duke

 

Duke

Energy

Progress

Energy

Energy

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Service cost

$

2

 

$

 

$

 

$

 

$

 

Interest cost on projected benefit obligation

14

 

1

 

5

 

1

 

2

 

Amortization of actuarial loss

8

 

1

 

1

 

1

 

1

 

Amortization of prior service credit

(1

)

 

 

 

 

Net periodic pension costs

$

23

 

$

2

 

$

6

 

$

2

 

$

3

 

 

 

Piedmont

 

Year Ended

(in millions)

October 31, 2016

Amortization of prior service cost

$

 

Settlement charge

1

 

Net periodic pension costs

$

1

 

 

 

Amounts Recognized in Accumulated Other Comprehensive Income and Regulatory Assets and Liabilities

 

Year Ended December 31, 2018

 

 

Duke

 

Duke

Duke

 

Duke

Energy

Progress

Energy

Energy

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Regulatory assets, net (decrease) increase

$

(16

)

$

1

 

$

(6

)

$

(3

)

$

(3

)

Accumulated other comprehensive (income) loss

 

 

 

 

 

Deferred income tax benefit

$

1

 

$

 

$

1

 

$

 

$

 

Actuarial gain arising during the year

(4

)

 

(3

)

 

 

Net amount recognized in accumulated other comprehensive loss (income)

$

(3

)

$

 

$

(2

)

$

 

$

 

 

Year Ended December 31, 2017

 

 

Duke

 

Duke

Duke

 

Duke

Energy

Progress

Energy

Energy

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Regulatory assets, net increase (decrease)

$

5

 

$

(1

)

$

3

 

$

1

 

$

2

 

Accumulated other comprehensive (income) loss

 

 

 

 

 

Prior service credit arising during the year

$

(1

)

$

 

$

 

$

 

$

 

Actuarial loss arising during the year

2

 

 

 

 

 

Net amount recognized in accumulated other comprehensive loss (income)

$

1

 

$

 

$

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

Reconciliation of Funded Status to Net Amount Recognized

 

Year Ended December 31, 2018

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Change in Projected Benefit Obligation

 

 

 

 

 

 

 

 

Obligation at prior measurement date

$

331

 

$

14

 

$

116

 

$

35

 

$

47

 

$

4

 

$

3

 

$

4

 

Service cost

2

 

1

 

 

 

 

 

 

 

Interest cost

12

 

 

4

 

1

 

2

 

 

 

 

Actuarial gain

(17

)

 

(6

)

(2

)

(3

)

(1

)

 

(1

)

Benefits paid

(24

)

(1

)

(8

)

(3

)

(3

)

 

 

 

Obligation at measurement date

$

304

 

$

14

 

$

106

 

$

31

 

$

43

 

$

3

 

$

3

 

$

3

 

Accumulated Benefit Obligation at measurement date

$

304

 

$

14

 

$

106

 

$

31

 

$

43

 

$

3

 

$

3

 

$

3

 

Change in Fair Value of Plan Assets

 

 

 

 

 

 

 

 

Benefits paid

$

(24

)

$

(1

)

$

(8

)

$

(3

)

$

(3

)

$

 

$

 

$

 

Employer contributions

24

 

1

 

8

 

3

 

3

 

 

 

 

Plan assets at measurement date

$

 

$

 

$

 

$

 

$

 

$

 

$

 

$

 

 

 

 

Year Ended December 31, 2017

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Change in Projected Benefit Obligation

 

 

 

 

 

 

 

 

Obligation at prior measurement date

$

332

 

$

14

 

$

114

 

$

33

 

$

46

 

$

4

 

$

3

 

$

4

 

Service cost

2

 

1

 

 

 

 

 

 

 

Interest cost

13

 

1

 

5

 

1

 

2

 

 

 

 

Actuarial loss (gain)

15

 

 

5

 

4

 

2

 

 

 

 

Benefits paid

(31

)

(2

)

(8

)

(3

)

(3

)

 

 

 

Obligation at measurement date

$

331

 

$

14

 

$

116

 

$

35

 

$

47

 

$

4

 

$

3

 

$

4

 

Accumulated Benefit Obligation at measurement date

$

331

 

$

14

 

$

116

 

$

35

 

$

47

 

$

4

 

$

3

 

$

4

 

Change in Fair Value of Plan Assets

 

 

 

 

 

 

 

 

Benefits paid

$

(31

)

$

(2

)

$

(8

)

$

(3

)

$

(3

)

$

 

$

 

$

Employer contributions

31

 

2

 

8

 

3

 

3

 

 

 

 

Plan assets at measurement date

$

 

$

 

$

 

$

 

$

 

$

 

$

 

$

 

 

 

 

 

Amounts Recognized in the Consolidated Balance Sheets

 

December 31, 2018

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Current pension liability(a)

$

21

 

$

2

 

$

8

 

$

3

 

$

3

 

$

 

$

 

$

 

Noncurrent pension liability(b)

283

 

12

 

98

 

28

 

40

 

3

 

3

 

3

 

Total accrued pension liability

$

304

 

$

14

 

$

106

 

$

31

 

$

43

 

$

3

 

$

3

 

$

3

 

Regulatory assets

$

62

 

$

5

 

$

15

 

$

5

 

$

10

 

$

1

 

$

 

$

1

 

Accumulated other comprehensive (income) loss

 

 

 

 

 

 

 

 

Deferred income tax benefit

$

(3

)

$

 

$

(2

)

$

 

$

 

$

 

$

 

$

 

Prior service credit

(1

)

 

 

 

 

 

 

 

Net actuarial loss

8

 

 

6

 

 

 

 

 

 

Net amounts recognized in accumulated other comprehensive loss

$

4

 

$

 

$

4

 

$

 

$

 

$

 

$

 

$

 

Amounts to be recognized in net periodic pension expense in the next year

 

 

 

 

 

 

 

 

Unrecognized net actuarial loss

$

6

 

$

 

$

2

 

$

1

 

$

1

 

$

 

$

 

$

 

Unrecognized prior service credit

(2

)

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Current pension liability(a)

$

23

 

$

2

 

$

8

 

$

3

 

$

3

 

$

 

$

 

$

 

Noncurrent pension liability(b)

308

 

12

 

108

 

32

 

44

 

4

 

3

 

4

 

Total accrued pension liability

$

331

 

$

14

 

$

116

 

$

35

 

$

47

 

$

4

 

$

3

 

$

4

 

Regulatory assets

$

78

 

$

4

 

$

21

 

$

8

 

$

13

 

$

1

 

$

 

$

1

 

Accumulated other comprehensive (income) loss

 

 

 

 

 

 

 

 

Deferred income tax benefit

$

(4

)

$

 

$

(3

)

$

 

$

 

$

 

$

 

$

 

Prior service credit

(1

)

 

 

 

 

 

 

 

Net actuarial loss

12

 

 

9

 

 

 

 

 

 

Net amounts recognized in accumulated other comprehensive loss

$

7

 

$

 

$

6

 

$

 

$

 

$

 

$

 

$

 

Amounts to be recognized in net periodic pension expense in the next year

 

 

 

 

 

 

 

 

Unrecognized net actuarial loss

$

8

 

$

 

$

2

 

$

1

 

$

1

 

$

 

$

 

$

 

Unrecognized prior service credit

$

(2

)

$

 

$

 

$

 

$

 

$

 

$

 

$

(a) Included in Other within Current Liabilities on the Consolidated Balance Sheets.

(b) Included in Accrued pension and other post-retirement benefit costs on the Consolidated Balance Sheets.

Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets

 

December 31, 2018

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Projected benefit obligation

$

304

 

$

14

 

$

106

 

$

31

 

$

43

 

$

3

 

$

3

 

$

3

 

Accumulated benefit obligation

304

 

14

 

106

 

31

 

43

 

3

 

3

 

3

 

 

 

December 31, 2017

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Projected benefit obligation

$

331

 

$

14

 

$

116

 

$

35

 

$

47

 

$

4

 

$

3

 

$

4

 

Accumulated benefit obligation

331

 

14

 

116

 

35

 

47

 

4

 

3

 

4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assumptions Used for Pension Benefits Accounting

The discount rate used to determine the current year pension obligation and following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality corporate bonds that generate sufficient cash flow to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected.

The average remaining service period of active covered employees is 10 years for Duke Energy, 13 years for Progress Energy, 11 years for Duke Energy Progress, 15 years for Duke Energy Florida, eight years for Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Piedmont. The following tables present the assumptions used for pension benefit accounting.

 

 

December 31,

 

 

2018

 

2017

 

2016

Benefit Obligations

 

 

 

 

 

 

 

 

 

 

Discount rate

 

 

 

4.30

%

 

 

 

3.60

%

 

4.10

%

Salary increase

 

3.50

%

4.00

%

 

3.50

%

4.00

%

 

4.40

%

Net Periodic Benefit Cost

 

 

 

 

 

 

 

 

 

 

Discount rate

 

 

 

3.60

%

 

 

 

4.10

%

 

4.40

%

Salary increase

 

3.50

%

4.00

%

 

 

 

4.40

%

 

4.40

%

 

 

 

Piedmont

 

 

Two Months Ended

 

Year Ended

 

 

December 31, 2016

 

October 31, 2016

Benefit Obligations

 

 

 

 

Discount rate

 

4.10

%

 

3.80

%

Net Periodic Benefit Cost

 

 

 

 

Discount rate

 

3.80

%

 

3.85

%

Expected Benefit Payments

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Years ending December 31,

 

 

 

 

 

 

 

 

2019

$

22

 

$

2

 

$

8

 

$

3

 

$

3

 

$

 

$

 

$

 

2020

21

 

1

 

8

 

2

 

3

 

 

 

 

2021

23

 

1

 

8

 

2

 

3

 

 

 

 

2022

25

 

1

 

8

 

2

 

3

 

 

 

 

2023

25

 

3

 

7

 

2

 

3

 

 

 

 

2024-2028

125

 

10

 

37

 

11

 

15

 

1

 

1

 

2

 

 

 

 

 

OTHER POST-RETIREMENT BENEFIT PLANS

Duke Energy provides, and the Subsidiary Registrants participate in, some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans. The health care benefits include medical, dental and prescription drug coverage and are subject to certain limitations, such as deductibles and copayments.

Duke Energy did not make any pre-funding contributions to its other post-retirement benefit plans during the years ended December 31, 2018, 2017 or 2016.

Components of Net Periodic Other Post-Retirement Benefit Costs

 

Year Ended December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Service cost

$

6

 

 

$

1

 

 

$

1

 

 

$

 

 

$

1

 

 

$

1

 

 

$

1

 

 

$

1

 

Interest cost on accumulated post-retirement benefit obligation

28

 

 

7

 

 

12

 

 

6

 

 

6

 

 

1

 

 

3

 

 

1

Expected return on plan assets

(13

)

 

(8

)

 

 

 

 

 

 

 

 

 

 

 

(2

)

Amortization of actuarial loss

6

 

 

3

 

 

1

 

 

1

 

 

 

 

 

 

4

 

 

 

Amortization of prior service credit

(19

)

 

(5

)

 

(8

)

 

(1

)

 

(7

)

 

(1

)

 

(1

)

 

(2

)

Net periodic post-retirement benefit costs (a)(b)

$

8

 

 

$

(2

)

 

$

6

 

 

$

6

 

 

$

 

 

$

1

 

 

$

7

 

 

$

(2

)

 

 

Year Ended December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Service cost

$

4

 

 

$

1

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

1

 

Interest cost on accumulated post-retirement benefit obligation

34

 

 

8

 

 

13

 

 

7

 

 

6

 

 

1

 

 

3

 

 

1

 

Expected return on plan assets

(14

)

 

(8

)

 

 

 

 

 

 

 

 

 

(1

)

 

(2

)

Amortization of actuarial loss (gain)

10

 

 

(2

)

 

21

 

 

12

 

 

9

 

 

(2

)

 

(1

)

 

1

 

Amortization of prior service credit

(115

)

 

(10

)

 

(84

)

 

(54

)

 

(30

)

 

 

 

(1

)

 

 

Curtailment credit (c)

(30

)

 

(4

)

 

(16

)

 

 

 

(16

)

 

(2

)

 

(2

)

 

 

Net periodic post-retirement benefit costs(a)(b)

$

(111

)

 

$

(15

)

 

$

(66

)

 

$

(35

)

 

$

(31

)

 

$

(3

)

 

$

(2

)

 

$

1

 

 

 

 

 

 

 

 

Year Ended December 31, 2016

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

Service cost

$

3

 

 

$

1

 

 

$

1

 

 

$

 

 

$

1

 

 

$

 

 

$

 

Interest cost on accumulated post-retirement benefit obligation

35

 

 

8

 

 

15

 

 

8

 

 

7

 

 

1

 

 

4

 

Expected return on plan assets

(12

)

 

(8

)

 

 

 

 

 

 

 

 

 

(1

)

Amortization of actuarial loss (gain)

6

 

 

(3

)

 

22

 

 

13

 

 

9

 

 

(2

)

 

(1

)

Amortization of prior service credit

(141

)

 

(14

)

 

(103

)

 

(68

)

 

(35

)

 

 

 

(1

)

Net periodic post-retirement benefit costs(a)(b)

$

(109

)

 

$

(16

)

 

$

(65

)

 

$

(47

)

 

$

(18

)

 

$

(1

)

 

$

1

(a) Duke Energy amounts exclude $7 million, $7 million and $8 million for the years ended December 2018, 2017 and 2016, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

(b) Duke Energy Ohio amounts exclude $2 million, $2 million and $2 million for the years ended December 2018, 2017 and 2016, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

(c) Curtailment credit resulted from a reduction in average future service of plan participants due to a plan amendment.

 

Piedmont

 

Year Ended

(in millions)

October 31, 2016

Service cost

$

1

 

Interest cost on projected benefit obligation

1

 

Expected return on plan assets

(2

)

Amortization of actuarial loss

1

 

Net periodic pension costs

$

1

 

 

 

 

 

 

 

 

 

Amounts Recognized in Accumulated Other Comprehensive Income and Regulatory Assets and Liabilities

 

Year Ended December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Regulatory assets, net increase (decrease)

$

137

 

 

$

 

 

$

133

 

 

$

84

 

 

$

49

 

 

$

 

 

$

(5

)

 

$

4

 

Regulatory liabilities, net increase (decrease)

$

154

 

 

$

(6

)

 

$

149

 

 

$

93

 

 

$

56

 

 

$

2

 

 

$

3

 

 

$

 

Accumulated other comprehensive (income) loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred income tax benefit

$

(1

)

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Amortization of prior year actuarial gain

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net amount recognized in accumulated other comprehensive income

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

 

Year Ended December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Regulatory assets, net increase (decrease)

$

71

 

 

$

 

 

$

81

 

 

$

42

 

 

$

39

 

 

$

 

 

$

(5

)

 

$

(11

)

Regulatory liabilities, net increase (decrease)

$

(27

)

 

$

(2

)

 

$

 

 

$

 

 

$

 

 

$

(3

)

 

$

(7

)

 

$

 

Accumulated other comprehensive (income) loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred income tax benefit

$

(1

)

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Amortization of prior year prior service credit

3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net amount recognized in accumulated other comprehensive income

$

2

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Piedmont's regulatory assets net decreased $1 million for the two months ended December 31, 2016, and increased $2 million for the year ended October 31, 2016.

 

 

 

 

Reconciliation of Funded Status to Accrued Other Post-Retirement Benefit Costs

 

Year Ended December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Change in Projected Benefit Obligation

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated post-retirement benefit obligation at prior measurement date

$

813

 

 

$

189

 

 

$

342

 

 

$

184

 

 

$

156

 

 

$

30

 

 

$

78

 

 

$

32

 

Service cost

6

 

 

1

 

 

1

 

 

 

 

1

 

 

1

 

 

1

 

 

1

Interest cost

28

 

 

7

 

 

12

 

 

6

 

 

6

 

 

1

 

 

3

 

 

1

 

Plan participants' contributions

18

 

 

3

 

 

6

 

 

4

 

 

3

 

 

1

 

 

2

 

 

 

Actuarial gains

(51

)

 

(8

)

 

(23

)

 

(9

)

 

(13

)

 

(2

)

 

(5

)

 

(1

)

Transfers

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1

)

Benefits paid

(86

)

 

(18

)

 

(35

)

 

(19

)

 

(16

)

 

(2

)

 

(12

)

 

(2

)

Accumulated post-retirement benefit obligation at measurement date

$

728

 

 

$

174

 

 

$

303

 

 

$

166

 

 

$

137

 

 

$

29

 

 

$

67

 

 

$

30

 

Change in Fair Value of Plan Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Plan assets at prior measurement date

$

225

 

 

$

133

 

 

$

 

 

$

 

 

$

 

 

$

7

 

 

$

11

 

 

$

31

 

Actual return on plan assets

(8

)

 

(5

)

 

 

 

 

 

 

 

 

 

 

 

(1

)

Benefits paid

(86

)

 

(18

)

 

(35

)

 

(19

)

 

(16

)

 

(2

)

 

(12

)

 

(2

)

Employer contributions

46

 

 

2

 

 

29

 

 

15

 

 

13

 

 

2

 

 

4

 

 

1

 

Plan participants' contributions

18

 

 

3

 

 

6

 

 

4

 

 

3

 

 

1

 

 

2

 

 

 

Plan assets at measurement date

$

195

 

 

$

115

 

 

$

 

 

$

 

 

$

 

 

$

8

 

 

$

5

 

 

$

29

 

Funded status of plan

$

(533

)

 

$

(59

)

 

$

(303

)

 

$

(166

)

 

$

(137

)

 

$

(21

)

 

$

(62

)

 

$

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Change in Projected Benefit Obligation

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated post-retirement benefit obligation at prior measurement date

$

868

 

 

$

201

 

 

$

357

 

 

$

191

 

 

$

164

 

 

$

32

 

 

$

83

 

 

$

39

 

Service cost

4

 

 

1

 

 

 

 

 

 

 

 

 

 

 

 

1

 

Interest cost

34

 

 

8

 

 

13

 

 

7

 

 

6

 

 

1

 

 

3

 

 

1

 

Plan participants' contributions

17

 

 

3

 

 

6

 

 

3

 

 

3

 

 

1

 

 

2

 

 

 

Actuarial losses (gains)

4

 

 

(3

)

 

4

 

 

1

 

 

3

 

 

 

 

3

 

 

1

 

Transfers

 

 

2

 

 

(1

)

 

 

 

(1

)

 

1

 

 

 

 

 

Plan amendments

(28

)

 

(5

)

 

(3

)

 

(1

)

 

(2

)

 

(2

)

 

(2

)

 

(9

)

Benefits paid

(86

)

 

(18

)

 

(34

)

 

(17

)

 

(17

)

 

(3

)

 

(11

)

 

(1

)

Accumulated post-retirement benefit obligation at measurement date

$

813

 

 

$

189

 

 

$

342

 

 

$

184

 

 

$

156

 

 

$

30

 

 

$

78

 

 

$

32

 

Change in Fair Value of Plan Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Plan assets at prior measurement date

$

244

 

 

$

137

 

 

$

1

 

 

$

 

 

$

 

 

$

7

 

 

$

22

 

 

$

29

 

Actual return on plan assets

25

 

 

15

 

 

1

 

 

 

 

 

 

2

 

 

1

 

 

3

 

Benefits paid

(86

)

 

(18

)

 

(34

)

 

(17

)

 

(17

)

 

(3

)

 

(11

)

 

(1

)

Employer contributions (reimbursements)

25

 

 

(4

)

 

26

 

 

14

 

 

14

 

 

 

 

(3

)

 

 

Plan participants' contributions

17

 

 

3

 

 

6

 

 

3

 

 

3

 

 

1

 

 

2

 

 

 

Plan assets at measurement date

$

225

 

 

$

133

 

 

$

 

 

$

 

 

$

 

 

$

7

 

 

$

11

 

 

$

31

 

Funded status of plan

$

(588

)

 

$

(56

)

 

$

(342

)

 

$

(184

)

 

$

(156

)

 

$

(23

)

 

$

(67

)

 

$

(1

)

 

 

 

 

 

 

 

 

 

 

Amounts Recognized in the Consolidated Balance Sheets

 

December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Current post-retirement liability(a)

$

8

 

 

$

 

 

$

5

 

 

$

3

 

 

$

2

 

 

$

2

 

 

$

 

 

$

 

Noncurrent post-retirement liability(b)

525

 

 

59

 

 

298

 

 

163

 

 

135

 

 

19

 

 

62

 

 

1

 

Total accrued post-retirement liability

$

533

 

 

$

59

 

 

$

303

 

 

$

166

 

 

$

137

 

 

$

21

 

 

$

62

 

 

$

1

 

Regulatory assets

$

262

 

 

$

 

 

$

262

 

 

$

164

 

 

$

98

 

 

$

 

 

$

41

 

 

$

 

Regulatory liabilities

$

301

 

 

$

38

 

 

$

149

 

 

$

93

 

 

$

56

 

 

$

18

 

 

$

67

 

 

$

 

Accumulated other comprehensive (income) loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred income tax expense

$

3

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Prior service credit

(2

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net actuarial gain

(9

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net amounts recognized in accumulated other comprehensive income

$

(8

)

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

Amounts to be recognized in net periodic pension expense in the next year

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrecognized net actuarial loss

$

4

 

 

$

2

 

 

$

1

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Unrecognized prior service credit

(19

)

 

(5

)

 

(7

)

 

(1

)

 

(6

)

 

(1

)

 

(1

)

 

(2

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Current post-retirement liability(a)

$

36

 

 

$

 

 

$

29

 

 

$

15

 

 

$

14

 

 

$

2

 

 

$

 

 

$

 

Noncurrent post-retirement liability(b)

552

 

 

56

 

 

313

 

 

169

 

 

142

 

 

21

 

 

67

 

 

1

 

Total accrued post-retirement liability

$

588

 

 

$

56

 

 

$

342

 

 

$

184

 

 

$

156

 

 

$

23

 

 

$

67

 

 

$

1

 

Regulatory assets

$

125

 

 

$

 

 

$

129

 

 

$

80

 

 

$

49

 

 

$

 

 

$

46

 

 

$

(4

)

Regulatory liabilities

$

147

 

 

$

44

 

 

$

 

 

$

 

 

$

 

 

$

16

 

 

$

64

 

 

$

 

Accumulated other comprehensive (income) loss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred income tax expense

$

4

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Prior service credit

(2

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net actuarial gain

(10

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net amounts recognized in accumulated other comprehensive income

$

(8

)

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

Amounts to be recognized in net periodic pension expense in the next year

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrecognized net actuarial loss (gain)

$

5

 

 

$

3

 

 

$

1

 

 

$

 

 

$

1

 

 

$

 

 

$

 

 

$

 

Unrecognized prior service credit

(19

)

 

(5

)

 

(7

)

 

(1

)

 

(6

)

 

(1

)

 

(1

)

 

(2

)

(a) Included in Other within Current Liabilities on the Consolidated Balance Sheets.

(b) Included in Accrued pension and other post-retirement benefit costs on the Consolidated Balance Sheets.

 

 

 

 

 

 

 

 

 

 

 

 

 

Assumptions Used for Other Post-Retirement Benefits Accounting

The discount rate used to determine the current year other post-retirement benefits obligation and following year’s other post-retirement benefits expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality corporate bonds that generate sufficient cash flow to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected. The average remaining service period of active covered employees is nine years for Duke Energy, eight years for Duke Energy Carolinas, seven years for Duke Energy Florida, Duke Energy Ohio, and Piedmont, and six years for Progress Energy, Duke Energy Progress, and Duke Energy Indiana.

The following tables present the assumptions used for other post-retirement benefits accounting.

 

 

December 31,

 

 

2018

 

2017

 

2016

Benefit Obligations

 

 

 

 

 

 

Discount rate

 

4.30

%

 

3.60

%

 

4.10

%

Net Periodic Benefit Cost

 

 

 

 

 

 

Discount rate

 

3.60

%

 

4.10

%

 

4.40

%

Expected long-term rate of return on plan assets

 

6.50

%

 

6.50

%

 

6.50

%

Assumed tax rate

 

35

%

 

35

%

 

35

%

 

 

 

Piedmont

 

 

Two Months Ended

 

Year Ended

 

 

December 31, 2016

 

October 31, 2016

Benefit Obligations

 

 

 

 

Discount rate

 

4.10

%

 

3.80

%

Net Periodic Benefit Cost

 

 

 

 

Discount rate

 

3.80

%

 

4.38

%

Expected long-term rate of return on plan assets

 

6.75

%

 

7.25

%

Assumed Health Care Cost Trend Rate

 

December 31,

 

2018

 

2017

Health care cost trend rate assumed for next year

6.50

%

 

7.00

%

Rate to which the cost trend is assumed to decline (the ultimate trend rate)

4.75

%

 

4.75

%

Year that rate reaches ultimate trend

2024

 

2024

 

 

 

 

Sensitivity to Changes in Assumed Health Care Cost Trend Rates

 

Year Ended December 31, 2018

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

1-Percentage Point Increase

 

 

 

 

 

 

 

 

Effect on total service and interest costs

$

1

 

$

 

$

1

 

$

1

 

$

 

$

 

$

 

$

 

Effect on post-retirement benefit obligation

22

 

5

 

9

 

5

 

4

 

1

 

2

 

1

 

1-Percentage Point Decrease

 

 

 

 

 

 

 

 

Effect on total service and interest costs

(1

)

 

(1

)

(1

)

 

 

 

 

Effect on post-retirement benefit obligation

(20

)

(5

)

(8

)

(5

)

(4

)

(1

)

(2

)

(1

)

 

Expected Benefit Payments

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Years ending December 31,

 

 

 

 

 

 

 

 

2019

$

81

 

$

19

 

$

30

 

$

16

 

$

14

 

$

3

 

$

9

 

$

2

 

2020

75

 

18

 

29

 

15

 

13

 

3

 

8

 

2

 

2021

71

 

18

 

28

 

15

 

13

 

3

 

7

 

2

 

2022

68

 

17

 

27

 

14

 

12

 

3

 

7

 

3

 

2023

64

 

16

 

26

 

14

 

12

 

3

 

6

 

3

 

2024-2028

266

 

64

 

109

 

59

 

50

 

11

 

26

 

12

 

PLAN ASSETS

Description and Allocations

Duke Energy Master Retirement Trust

Assets for both the qualified pension and other post-retirement benefits are maintained in the Duke Energy Master Retirement Trust. Qualified pension and other post-retirement assets related to Piedmont were transferred into the Duke Energy Master Retirement Trust during 2017. Approximately 98 percent of the Duke Energy Master Retirement Trust assets were allocated to qualified pension plans and approximately 2 percent were allocated to other post-retirement plans (comprised of 401(h) accounts), as of December 31, 2018, and 2017. The investment objective of the Duke Energy Master Retirement Trust is to invest in a diverse portfolio of assets that is expected to generate positive surplus return over time (i.e. asset growth greater than liability growth) subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants.

As of December 31, 2018, Duke Energy assumes pension and other post-retirement plan assets will generate a long-term rate of return of 6.85 percent. The expected long-term rate of return was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers, where applicable. The asset allocation targets were set after considering the investment objective and the risk profile. Equity securities are held for their higher expected returns. Debt securities are primarily held to hedge the qualified pension plan liability. Real assets, return seeking fixed income, hedge funds and other global securities are held for diversification. Investments within asset classes are diversified to achieve broad market participation and reduce the impact of individual managers or investments.

Effective January 1, 2019, the target asset allocation for the Duke Energy Retirement Master Trust is 58 percent liability hedging assets and 42 percent return-seeking assets. Duke Energy periodically reviews its asset allocation targets, and over time, as the funded status of the benefit plans increase, the level of asset risk relative to plan liabilities may be reduced to better manage Duke Energy's benefit plan liabilities and reduce funded status volatility.

The Duke Energy Master Retirement Trust is authorized to engage in the lending of certain plan assets. Securities lending is an investment management enhancement that utilizes certain existing securities of the Duke Energy Master Retirement Trust to earn additional income. Securities lending involves the loaning of securities to approved parties. In return for the loaned securities, the Duke Energy Master Retirement Trust receives collateral in the form of cash and securities as a safeguard against possible default of any borrower on the return of the loan under terms that permit the Duke Energy Master Retirement Trust to sell the securities. The Duke Energy Master Retirement Trust mitigates credit risk associated with securities lending arrangements by monitoring the fair value of the securities loaned, with additional collateral obtained or refunded as necessary. The fair value of securities on loan was approximately $154 million and $195 million at December 31, 2018, and 2017, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned at December 31, 2018, and 2017, respectively. Securities lending income earned by the Duke Energy Master Retirement Trust was immaterial for the years ended December 31, 2018, 2017 and 2016, respectively.

Qualified pension and other post-retirement benefits for the Subsidiary Registrants are derived from the Duke Energy Master Retirement Trust, as such, each are allocated their proportionate share of the assets discussed below.

The following table includes the target asset allocations by asset class at December 31, 2018, and the actual asset allocations for the Duke Energy Master Retirement Trust.

 

 

 

Actual Allocation at

 

Target

 

December 31,

 

Allocation

 

2018

 

2017

U.S. equity securities

10

%

 

11

%

 

11

%

Non-U.S. equity securities

8

%

 

8

%

 

8

%

Global equity securities

10

%

 

10

%

 

10

%

Global private equity securities

3

%

 

2

%

 

2

%

Debt securities

63

%

 

63

%

 

63

%

Hedge funds

2

%

 

2

%

 

2

%

Real estate and cash

2

%

 

2

%

 

2

%

Other global securities

2

%

 

2

%

 

2

%

Total

100

%

 

100

%

 

100

%

Other post-retirement assets

Duke Energy's other post-retirement assets are comprised of VEBA trusts and 401(h) accounts held within the Duke Energy Master Retirement Trust. Duke Energy's investment objective is to achieve sufficient returns, subject to a prudent level of portfolio risk, for the purpose of promoting the security of plan benefits for participants.

The following table presents target and actual asset allocations for the VEBA trusts at December 31, 2018.

 

 

 

Actual Allocation at

 

Target

 

December 31,

 

Allocation

 

2018

 

2017

U.S. equity securities

32

%

 

43

%

 

41

%

Non-U.S. equity securities

6

%

 

8

%

 

8

%

Real estate

2

%

 

2

%

 

2

%

Debt securities

45

%

 

40

%

 

36

%

Cash

15

%

 

7

%

 

13

%

Total

100

%

 

100

%

 

100

%

 

Fair Value Measurements

Duke Energy classifies recurring and non-recurring fair value measurements based on the fair value hierarchy as discussed in Note 16.

Valuation methods of the primary fair value measurements disclosed below are as follows:

Investments in equity securities

Investments in equity securities are typically valued at the closing price in the principal active market as of the last business day of the reporting period. Principal active markets for equity prices include published exchanges such as NASDAQ and NYSE. Foreign equity prices are translated from their trading currency using the currency exchange rate in effect at the close of the principal active market. Prices have not been adjusted to reflect after-hours market activity. The majority of investments in equity securities are valued using Level 1 measurements. When the price of an institutional commingled fund is unpublished, it is not categorized in the fair value hierarchy, even though the funds are readily available at the fair value.

Investments in corporate debt securities and U.S. government securities

Most debt investments are valued based on a calculation using interest rate curves and credit spreads applied to the terms of the debt instrument (maturity and coupon interest rate) and consider the counterparty credit rating. Most debt valuations are Level 2 measurements. If the market for a particular fixed-income security is relatively inactive or illiquid, the measurement is Level 3. U.S. Treasury debt is typically Level 2.

Investments in short-term investment funds

Investments in short-term investment funds are valued at the net asset value of units held at year end and are readily redeemable at the measurement date. Investments in short-term investment funds with published prices are valued as Level 1. Investments in short-term investment funds with unpublished prices are valued as Level 2.

Investments in real estate limited partnerships

Investments in real estate limited partnerships are valued by the trustee at each valuation date (monthly). As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis, conducted by reputable, independent appraisal firms, and signed by appraisers that are members of the Appraisal Institute, with the professional designation MAI. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three valuation techniques that can be used to value investments in real estate assets: the market, income or cost approach. The appropriateness of each valuation technique depends on the type of asset or business being valued. In addition, the trustee may cause additional appraisals to be performed as warranted by specific asset or market conditions. Property valuations and the salient valuation-sensitive assumptions of each direct investment property are reviewed by the trustee quarterly and values are adjusted if there has been a significant change in circumstances related to the investment property since the last valuation. Value adjustments for interim capital expenditures are only recognized to the extent that the valuation process acknowledges a corresponding increase in fair value. An independent firm is hired to review and approve quarterly direct real estate valuations. Key inputs and assumptions used to determine fair value includes among others, rental revenue and expense amounts and related revenue and expense growth rates, terminal capitalization rates and discount rates. Development investments are valued using cost incurred to date as a primary input until substantive progress is achieved in terms of mitigating construction and leasing risk at which point a discounted cash flow approach is more heavily weighted. Key inputs and assumptions in addition to those noted above used to determine the fair value of development investments include construction costs and the status of construction completion and leasing. Investments in real estate limited partnerships are valued at net asset value of units held at year end and are not readily redeemable at the measurement date. Investments in real estate limited partnerships are not categorized within the fair value hierarchy.

 

 

 

 

 

 

 

Duke Energy Master Retirement Trust

The following tables provide the fair value measurement amounts for the Duke Energy Master Retirement Trust qualified pension and other post-retirement assets.

 

December 31, 2018

 

Total Fair

 

 

 

 

 

 

 

Not

(in millions)

Value

 

Level 1

 

Level 2

 

Level 3

 

Categorized(b)

Equity securities

$

2,373

 

 

$

1,751

 

 

$

 

 

$

 

 

$

622

 

Corporate debt securities

4,054

 

 

 

 

4,054

 

 

 

 

 

Short-term investment funds

363

 

 

279

 

 

84

 

 

 

 

 

Partnership interests

120

 

 

 

 

 

 

 

 

120

 

Hedge funds

226

 

 

 

 

 

 

 

 

226

 

Real estate limited partnerships

144

 

 

 

 

 

 

 

 

144

 

U.S. government securities

961

 

 

 

 

961

 

 

 

 

 

Guaranteed investment contracts

27

 

 

 

 

 

 

27

 

 

 

Governments bonds – foreign

30

 

 

 

 

30

 

 

 

 

 

Cash

28

 

 

28

 

 

 

 

 

 

 

Net pending transactions and other investments

(2

)

 

(6

)

 

4

 

 

 

 

 

Total assets(a)

$

8,324

 

 

$

2,052

 

 

$

5,133

 

 

$

27

 

 

$

1,112

 

(a) Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, Duke Energy Indiana, and Piedmont were allocated approximately 27 percent, 31 percent, 15 percent, 16 percent, 5 percent, 7 percent, and 4 percent, respectively, of the Duke Energy Master Retirement Trust at December 31, 2018. Accordingly, all amounts included in the table above are allocable to the Subsidiary Registrants using these percentages.

(b) Certain investments that are measured at fair value using the net asset value per share practical expedient have not been categorized in the fair value hierarchy.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

Total Fair

 

 

 

 

 

 

 

Not

(in millions)

Value

 

Level 1

 

Level 2

 

Level 3

 

Categorized(b)

Equity securities

$

2,823

 

 

$

1,976

 

 

$

 

 

$

 

 

$

847

 

Corporate debt securities

4,694

 

 

 

 

4,694

 

 

 

 

 

Short-term investment funds

246

 

 

192

 

 

54

 

 

 

 

 

Partnership interests

137

 

 

 

 

 

 

 

 

137

 

Hedge funds

226

 

 

 

 

 

 

 

 

226

 

Real estate limited partnerships

135

 

 

 

 

 

 

 

 

135

 

U.S. government securities

762

 

 

 

 

762

 

 

 

 

 

Guaranteed investment contracts

28

 

 

 

 

 

 

28

 

 

 

Governments bonds – foreign

38

 

 

 

 

38

 

 

 

 

 

Cash

6

 

 

6

 

 

 

 

 

 

 

Government and commercial mortgage backed securities

2

 

 

 

 

2

 

 

 

 

 

Net pending transactions and other investments

17

 

 

15

 

 

2

 

 

 

 

 

Total assets(a)

$

9,114

 

 

$

2,189

 

 

$

5,552

 

 

$

28

 

 

$

1,345

 

(a) Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, Duke Energy Indiana, and Piedmont were allocated approximately 27 percent, 30 percent, 15 percent, 15 percent, 5 percent, 8 percent, and 4 percent, respectively, of the Duke Energy Master Retirement Trust and Piedmont's Pension assets at December 31, 2017. Accordingly, all amounts included in the table above are allocable to the Subsidiary Registrants using these percentages.

(b) Certain investments that are measured at fair value using the net asset value per share practical expedient have not been categorized in the fair value hierarchy.

The following table provides a reconciliation of beginning and ending balances of Duke Energy Master Retirement Trust qualified pension and other post-retirement assets at fair value on a recurring basis where the determination of fair value includes significant unobservable inputs (Level 3).

(in millions)

2018

 

2017(a)

Balance at January 1

$

28

 

 

$

38

 

Sales

(1

)

 

(2

)

Total gains and other, net

 

 

1

 

Transfer of Level 3 assets to other classifications

 

 

(9

)

Balance at December 31

$

27

 

 

$

28

 

(a) Balance at January 1 includes $9 million associated with Piedmont pension assets.

 

 

 

 

Other post-retirement assets

The following tables provide the fair value measurement amounts for VEBA trust assets.

 

December 31, 2018

 

Total Fair

 

 

(in millions)

Value

 

Level 2

Cash and cash equivalents

$

3

 

 

$

3

 

Real estate

1

 

 

1

 

Equity securities

25

 

 

25

 

Debt securities

20

 

 

20

 

Total assets

$

49

 

 

$

49

 

 

 

December 31, 2017

 

Total Fair

 

 

(in millions)

Value

 

Level 2

Cash and cash equivalents

$

8

 

 

$

8

Real estate

1

 

 

1

 

Equity securities

28

 

 

28

 

Debt securities

21

 

 

21

 

Total assets

$

58

 

 

$

58

 

EMPLOYEE SAVINGS PLANS

Retirement Savings Plan

Duke Energy or its affiliates sponsor, and the Subsidiary Registrants participate in, employee savings plans that cover substantially all U.S. employees. Most employees participate in a matching contribution formula where Duke Energy provides a matching contribution generally equal to 100 percent of employee before-tax and Roth 401(k) contributions of up to 6 percent of eligible pay per pay period. Dividends on Duke Energy shares held by the savings plans are charged to retained earnings when declared and shares held in the plans are considered outstanding in the calculation of basic and diluted EPS.

For new and rehired employees who are not eligible to participate in Duke Energy’s defined benefit plans, an additional employer contribution of 4 percent of eligible pay per pay period, which is subject to a three-year vesting schedule, is provided to the employee’s savings plan account. Certain Piedmont employees whose participation in a prior Piedmont defined benefit plan (that was frozen as of December 31, 2017) are eligible for employer transition credit contributions of 3 to 5 percent of eligible pay per period, for each pay period during the three-year period ending December 31, 2020.

 

 

 

 

 

 

 

 

The following table includes pretax employer matching contributions made by Duke Energy and expensed by the Subsidiary Registrants.

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont(a)

Years ended December 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2018

$

213

 

 

$

68

 

 

$

58

 

 

$

40

 

 

$

19

 

 

$

4

 

 

$

10

 

 

$

12

 

2017

179

 

 

61

 

 

53

 

 

37

 

 

16

 

 

3

 

 

9

 

 

7

 

2016

169

 

 

57

 

 

50

 

 

35

 

 

15

 

 

3

 

 

8

 

 

 

(a) Piedmont's pretax employer matching contributions were $1 million and $7 million during the two months ended December 31, 2016, and for the year ended October 31, 2016, respectively.

Money Purchase Pension Plan

Piedmont sponsored the MPP plan, which is a defined contribution pension plan that allowed employees to direct investments and assume risk of investment returns. Under the MPP plan, Piedmont annually deposited a percentage of each participant’s pay into an account of the MPP plan. This contribution equaled 4 percent of the participant’s eligible compensation plus an additional 4 percent of eligible compensation above the Social Security wage base up to the IRS compensation limit. The participant was vested in MPP plan after three years of service. No contributions were made to the MPP plan during the two months ended December 31, 2016. Piedmont contributed $2 million to the MPP plan during each of the years ended December 31, 2017, and October 31, 2016. Effective December 31, 2017, the MPP Plan was merged into the Retirement Savings Plan and the money purchase plan formula was discontinued. Beginning with the 2018 plan year, the former MPP Plan participants are eligible to receive the additional employer contribution under the Retirement Savings Plan, discussed above.

 

23. INCOME TAXES

Tax Act

On December 22, 2017, President Trump signed the Tax Act into law. Among other provisions, the Tax Act lowered the corporate federal income tax rate from 35 to 21 percent, limits interest deductions outside of regulated utility operations, requires the normalization of excess deferred taxes associated with property under the average rate assumption method as a prerequisite to qualifying for accelerated depreciation and repealed the federal manufacturing deduction. The Tax Act also repealed the corporate AMT and stipulates a refund of 50 percent of remaining AMT credit carryforwards (to the extent the credits exceed regular tax for the year) for tax years 2018, 2019 and 2020 with all remaining AMT credits to be refunded in tax year 2021.

On December 22, 2017, the SEC staff issued SAB 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act, which provides guidance on accounting for the Tax Act’s impact. SAB 118 provides a measurement period, which in no case should extend beyond one year from the Tax Act enactment date, during which a company acting in good faith may complete the accounting for the impacts of the Tax Act under ASC Topic 740. In accordance with SAB 118, a company must reflect the income tax effects of the Tax Act in the reporting period in which the accounting under ASC Topic 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete, a company can determine a reasonable estimate for those effects and record a provisional estimate in the financial statements in the first reporting period in which a reasonable estimate can be determined.

 

 

 

As of December 31, 2018, the accounting for the effects of the Tax Act is complete. During the year ended December 31, 2018, Duke Energy recorded the following measurement period adjustments in accordance with SAB 118:

  • Additional tax expense of $23 million related to the completion of the analysis of Duke Energy’s existing regulatory liability related to deferred taxes;

  • A $10 million tax benefit for the remeasurement of deferred tax assets and deferred tax liabilities primarily related to the guidance on bonus depreciation issued by the IRS in August 2018 affecting the computation of the Company's 2017 Federal income tax liability;

  • Additional tax expense of $7 million related to the portion of the deferred tax asset as of December 31, 2017, that represents nondeductible long-term incentives under the Tax Act’s limitation on the deductibility of executive compensation; and

  • During the fourth quarter of 2018, the Company released the $76 million valuation allowance that it recorded in the first quarter of 2018 as a result of additional guidance published by the IRS that stated refundable AMT credits would not be subject to sequestration.

  • The majority of Duke Energy’s operations are regulated and it is expected that the Subsidiary Registrants will ultimately pass on the savings associated with the amount representing the remeasurement of deferred tax balances related to regulated operations to customers. For Duke Energy's regulated operations, where the reduction is expected to be returned to customers in future rates, the remeasurement has been deferred as a regulatory liability. During 2018, Duke Energy recorded an additional regulatory liability of $83 million, representing the revaluation of those deferred tax balances. The Subsidiary Registrants continue to respond to requests from regulators in various jurisdictions to determine the timing and magnitude of savings they will pass on to customers.

In addition, during 2018 Duke Energy reclassified $573 million of AMT credit carryforwards from noncurrent deferred tax liabilities to a current federal income tax receivable as the Company expects to receive this amount via a refund from the IRS in 2019, based on the expected filing of Duke Energy's 2018 income tax return in the second quarter of 2019.

Income Tax Expense

Components of Income Tax Expense

 

Year Ended December 31, 2018

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Current income taxes

 

 

 

 

 

 

 

 

Federal

$

(647

)

$

(8

)

$

(135

)

$

(71

)

$

(49

)

$

20

 

$

29

 

$

67

 

State

(11

)

6

 

(5

)

(5

)

(10

)

(1

)

3

 

1

 

Foreign

3

 

 

 

 

 

 

 

 

Total current income taxes

(655

)

(2

)

(140

)

(76

)

(59

)

19

 

32

 

68

 

Deferred income taxes

 

 

 

 

 

 

 

 

Federal

1,064

 

299

 

341

 

256

 

115

 

21

 

74

 

(36

)

State

49

 

11

 

20

 

(17

)

45

 

3

 

22

 

5

 

Total deferred income taxes(a)(b)

1,113

 

310

 

361

 

239

 

160

 

24

 

96

 

(31

)

Investment tax credit amortization

(10

)

(5

)

(3

)

(3

)

 

 

 

 

Income tax expense from continuing operations

448

 

303

 

218

 

160

 

101

 

43

 

128

 

37

 

Tax benefit from discontinued operations

(26

)

 

 

 

 

 

 

 

Total income tax expense included in Consolidated Statements of Operations

$

422

 

$

303

 

$

218

 

$

160

 

$

101

 

$

43

 

$

128

 

$

37

 

(a) Includes benefits of NOL carryforwards and tax credit carryforwards of $22 million at Duke Energy Carolinas, $293 million at Progress Energy, $59 million at Duke Energy Progress, $219 million at Duke Energy Florida, $17 million at Duke Energy Ohio, $21 million at Duke Energy Indiana and $39 million at Piedmont. In addition, total deferred income taxes includes utilization of NOL carryforwards and tax credit carryforwards of $18 million at Duke Energy.

(b) For the year ended December 31, 2018, the Company has revised the December 31, 2017, estimates of the income tax effects of the Tax Act, in accordance with SAB 118. See the Statutory Rate Reconciliation section below for additional information on the Tax Act's impact on income tax expense.

 

Year Ended December 31, 2017

 

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Current income taxes

 

 

 

 

 

 

 

 

Federal

$

(247

)

$

221

 

$

(436

)

$

(95

)

$

(188

)

$

(37

)

$

128

 

$

(90

)

State

4

 

20

 

(5

)

2

 

(11

)

2

 

21

 

(3

)

Foreign

3

 

 

 

 

 

 

 

 

Total current income taxes

(240

)

241

 

(441

)

(93

)

(199

)

(35

)

149

 

(93

)

Deferred income taxes

 

 

 

 

 

 

 

 

Federal

1,344

 

381

 

664

 

378

 

194

 

99

 

138

 

147

 

State

102

 

35

 

44

 

10

 

51

 

(4

)

14

 

8

 

Total deferred income taxes(a)(b)

1,446

 

416

 

708

 

388

 

245

 

95

 

152

 

155

 

Investment tax credit amortization

(10

)

(5

)

(3

)

(3

)

 

(1

)

 

 

Income tax expense from continuing operations

1,196

 

652

 

264

 

292

 

46

 

59

 

301

 

62

 

Tax benefit from discontinued operations

(6

)

 

 

 

 

 

 

 

Total income tax expense included in Consolidated Statements of Operations

$

1,190

 

$

652

 

$

264

 

$

292

 

$

46

 

$

59

 

$

301

 

$

62

 

(a) Includes utilization of NOL carryforwards and tax credit carryforwards of $428 million at Duke Energy, $74 million at Progress Energy, $36 million at Duke Energy Florida, $17 million at Duke Energy Ohio, $42 million at Duke Energy Indiana and $79 million at Piedmont. In addition, total deferred income taxes includes benefits of NOL carryforwards and tax credit carryforwards of $10 million at Duke Energy Carolinas and $1 million at Duke Energy Progress.

(b) As a result of the Tax Act, Duke Energy's deferred tax assets and liabilities were revalued as of December 31, 2017. See the Statutory Rate Reconciliation section below for additional information on the Tax Act's impact on income tax expense.

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2016

 

 

Duke

 

Duke

Duke

Duke

Duke

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Current income taxes

 

 

 

 

 

 

 

Federal

$

 

$

139

 

$

15

 

$

(59

)

$

76

 

$

(7

)

$

7

 

State

(15

)

25

 

(19

)

(25

)

22

 

(13

)

6

 

Foreign

2

 

 

 

 

 

 

 

Total current income taxes

(13

)

164

 

(4

)

(84

)

98

 

(20

)

13

 

Deferred income taxes

 

 

 

 

 

 

 

Federal

1,064

 

430

 

486

 

350

 

199

 

88

 

202

 

State

117

 

45

 

50

 

40

 

25

 

11

 

11

 

Total deferred income taxes(a)

1,181

 

475

 

536

 

390

 

224

 

99

 

213

 

Investment tax credit amortization

(12

)

(5

)

(5

)

(5

)

 

(1

)

(1

)

Income tax expense from continuing operations

1,156

 

634

 

527

 

301

 

322

 

78

 

225

 

Tax (benefit) expense from discontinued operations

(30

)

 

1

 

 

 

(36

)

 

Total income tax expense included in Consolidated Statements of Operations

$

1,126

 

$

634

 

$

528

 

$

301

 

$

322

 

$

42

 

$

225

 

(a) Includes benefits of NOL carryforwards and utilization of NOL and tax credit carryforwards of $648 million at Duke Energy, $4 million at Duke Energy Carolinas, $190 million at Progress Energy, $60 million at Duke Energy Progress, $49 million at Duke Energy Florida, $26 million at Duke Energy Ohio and $58 million at Duke Energy Indiana.

 

Piedmont

 

Two Months Ended

Year Ended October 31,

(in millions)

December 31, 2016

2016

Current income taxes

 

 

Federal

$

4

 

$

27

 

State

(2

)

12

 

Total current income taxes

2

 

39

 

Deferred income taxes

 

 

Federal

24

 

79

 

State

6

 

6

 

Total deferred income taxes(a)

30

 

85

 

Total income tax expense from continuing operations included in Consolidated Statements of Operations

$

32

 

$

124

 

(a) Includes benefits of NOL and tax carryforwards of $17 million and $91 million for the two months ended December 31, 2016, and the year ended October 31, 2016, respectively.

 

 

 

Duke Energy Income from Continuing Operations before Income Taxes

 

Years Ended December 31,

(in millions)

2018

 

2017

 

2016

Domestic(a)

$

3,018

 

 

$

4,207

 

 

$

3,689

 

Foreign

55

 

 

59

 

 

45

 

Income from continuing operations before income taxes

$

3,073

 

 

$

4,266

 

 

$

3,734

 

(a) Includes a $16 million expense in 2017 related to the Tax Act impact on equity earnings included within Equity in earnings (losses) of unconsolidated affiliates on the Consolidated Statement of Operations.

Taxes on Foreign Earnings

In February 2016, Duke Energy announced it had initiated a process to divest the International Disposal Group and, accordingly, no longer intended to indefinitely reinvest post-2014 undistributed foreign earnings. This change in the company's intent, combined with the extension of bonus depreciation by Congress in late 2015, allowed Duke Energy to more efficiently utilize foreign tax credits and reduce U.S. deferred tax liabilities associated with the historical unremitted foreign earnings by approximately $95 million during the year ended December 31, 2016.

Due to the classification of the International Disposal Group as discontinued operations beginning in the fourth quarter of 2016, income tax amounts related to the International Disposal Group's foreign earnings are presented within Income (Loss) From Discontinued Operations, net of tax on the Consolidated Statements of Operations. In December 2016, Duke Energy closed on the sale of the International Disposal Group in two separate transactions to execute the divestiture. See Note 2 for additional information on the sale.

Statutory Rate Reconciliation

The following tables present a reconciliation of income tax expense at the U.S. federal statutory tax rate to the actual tax expense from continuing operations.

 

Year Ended December 31, 2018

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Income tax expense, computed at the statutory rate of 21 percent

$

645

 

$

288

 

$

263

 

$

174

 

$

137

 

$

46

 

$

109

 

$

35

 

State income tax, net of federal income tax effect

30

 

14

 

13

 

(17

)

28

 

2

 

20

 

4

 

Amortization of excess deferred income tax

(61

)

 

(55

)

(1

)

(54

)

(3

)

(2

)

AFUDC equity income

(42

)

(15

)

(22

)

(12

)

(10

)

(2

)

(2

)

 

AFUDC equity depreciation

31

 

18

 

9

 

5

 

4

 

1

 

4

 

 

Renewable energy production tax credits

(129

)

 

 

 

 

 

 

 

Other tax credits

(28

)

(7

)

(13

)

(5

)

(8

)

(1

)

(1

)

(3

)

Tax Act(a)

20

 

1

 

25

 

19

 

 

2

 

 

 

Other items, net

(18

)

4

 

(2

)

(3

)

4

 

(2

)

 

1

 

Income tax expense from continuing operations

$

448

 

$

303

 

$

218

 

$

160

 

$

101

 

$

43

 

$

128

 

$

37

 

Effective tax rate

14.6

%

22.1

%

17.4

%

19.3

%

15.4

%

19.6

%

24.6

%

22.3

%

(a) For the year ended December 31, 2018, the Company revised the December 31, 2017 estimates of the income tax effects of the Tax Act, in accordance with SAB 118. Amounts primarily include but are not limited to items that are excluded for ratemaking purposes related certain wholesale fixed rate contracts, remeasurement of nonregulated net deferred tax liabilities, Federal net operating losses, and valuation allowance on foreign tax credits.

 

Year Ended December 31, 2017

 

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Income tax expense, computed at the statutory rate of 35 percent

$

1,493

 

$

653

 

$

536

 

$

353

 

$

265

 

$

88

 

$

229

 

$

70

 

State income tax, net of federal income tax effect

69

 

36

 

25

 

8

 

26

 

(1

)

23

 

3

 

AFUDC equity income

(81

)

(37

)

(32

)

(17

)

(16

)

(4

)

(8

)

 

Renewable energy production tax credits

(132

)

 

 

 

 

 

 

 

Tax Act(a)

(112

)

15

 

(246

)

(40

)

(226

)

(23

)

55

 

(12

)

Tax true up

(52

)

(24

)

(19

)

(13

)

(7

)

(5

)

(6

)

 

Other items, net

11

 

9

 

 

1

 

4

 

4

 

8

 

1

 

Income tax expense from continuing operations

$

1,196

 

$

652

 

$

264

 

$

292

 

$

46

 

$

59

 

$

301

 

$

62

 

Effective tax rate

28.0

%

34.9

%

17.2

%

29.0

%

6.1

%

23.4

%

46.0

%

30.8

%

(a) Amounts primarily include but are not limited to items that are excluded for ratemaking purposes related to abandoned or impaired assets, certain wholesale fixed rate contracts, remeasurement of nonregulated net deferred tax liabilities, Federal net operating losses, and valuation allowance on foreign tax credits.

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2016

 

 

Duke

 

Duke

Duke

Duke

Duke

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Income tax expense, computed at the statutory rate of 35 percent

$

1,307

 

$

630

 

$

548

 

$

315

 

$

306

 

$

95

 

$

212

 

State income tax, net of federal income tax effect

64

 

46

 

20

 

10

 

30

 

(2

)

11

 

AFUDC equity income

(70

)

(36

)

(26

)

(17

)

(9

)

(2

)

(6

)

Renewable energy production tax credits

(97

)

 

 

 

 

 

 

Audit adjustment

5

 

3

 

 

 

 

 

 

Tax true up

(14

)

(14

)

(11

)

(3

)

(9

)

(16

)

2

 

Other items, net

(39

)

5

 

(4

)

(4

)

4

 

3

 

6

 

Income tax expense from continuing operations

$

1,156

 

$

634

 

$

527

 

$

301

 

$

322

 

$

78

 

$

225

 

Effective tax rate

31.0

%

35.2

%

33.7

%

33.4

%

36.9

%

28.9

%

37.1

%

 

 

Piedmont

 

Two Months Ended

Year Ended October 31,

(in millions)

December 31, 2016

2016

Income tax expense, computed at the statutory rate of 35 percent

$

30

 

$

111

 

State income tax, net of federal income tax effect

1

 

11

 

Other items, net

1

 

2

 

Income tax expense from continuing operations

$

32

 

$

124

 

Effective tax rate

37.2

%

39.1

%

Valuation allowances have been established for certain state NOL carryforwards and state income tax credits that reduce deferred tax assets to an amount that will be realized on a more-likely-than-not basis. The net change in the total valuation allowance is included in the State income tax, net of federal income tax effect in the above tables.

 

 

 

 

 

 

 

 

 

 

 

 

DEFERRED TAXES

Net Deferred Income Tax Liability Components

 

December 31, 2018

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Deferred credits and other liabilities

$

164

 

$

64

 

$

35

 

$

53

 

$

 

$

17

 

$

6

 

$

17

 

Capital lease obligations

60

 

26

 

 

 

 

 

2

 

Pension, post-retirement and other employee benefits

347

 

24

 

110

 

47

 

58

 

16

 

24

 

(1

)

Progress Energy merger purchase accounting adjustments(a)

483

 

 

 

 

 

 

 

 

Tax credits and NOL carryforwards

4,580

 

257

 

693

 

215

 

363

 

42

 

237

 

110

 

Regulatory liabilities and deferred credits

 

 

 

 

 

56

 

 

48

 

Investments and other assets

 

 

 

 

 

18

 

 

16

 

Other

25

 

6

 

5

 

5

 

 

1

 

(1

)

 

Valuation allowance

(484

)

 

 

 

 

 

 

 

Total deferred income tax assets

5,175

 

377

 

843

 

320

 

421

 

150

 

268

 

190

 

Investments and other assets

(1,317

)

(795

)

(430

)

(272

)

(163

)

 

(5

)

 

Accelerated depreciation rates

(10,124

)

(3,207

)

(3,369

)

(1,735

)

(1,670

)

(967

)

(1,081

)

(733

)

Regulatory assets and deferred debits, net

(1,540

)

(64

)

(985

)

(432

)

(574

)

 

(191

)

 

Other

 

 

 

 

 

 

 

(8

)

Total deferred income tax liabilities

(12,981

)

(4,066

)

(4,784

)

(2,439

)

(2,407

)

(967

)

(1,277

)

(741

)

Net deferred income tax liabilities

$

(7,806

)

$

(3,689

)

$

(3,941

)

$

(2,119

)

$

(1,986

)

$

(817

)

$

(1,009

)

$

(551

)

(a) Primarily related to capital lease obligations and debt fair value adjustments.

The following table presents the expiration of tax credits and NOL carryforwards.

 

December 31, 2018

(in millions)

Amount

 

Expiration Year

Investment tax credits

$

1,614

 

 

2024

 

 

2038

Alternative minimum tax credits

574

 

 

Refundable by 2021

Federal NOL carryforwards(a)(e)

788

 

 

2022

 

 

Indefinite

State NOL carryforwards and credits(b)(e)

301

 

 

2019

 

 

Indefinite

Foreign NOL carryforwards(c)

12

 

 

2027

 

 

2037

Foreign Tax Credits(d)

1,271

 

 

2024

 

 

2027

Charitable contribution carryforwards

20

 

 

2019

 

 

2023

Total tax credits and NOL carryforwards

$

4,580

 

 

 

 

 

 

 

(a) A valuation allowance of $4 million has been recorded on the Federal NOL carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

(b) A valuation allowance of $85 million has been recorded on the state NOL carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

(c) A valuation allowance of $12 million has been recorded on the foreign NOL carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

(d) A valuation allowance of $383 million has been recorded on the foreign tax credits, as presented in the Net Deferred Income Tax Liability Components table.

(e) Indefinite carryforward for Federal NOLs, and NOLs for states that have adopted the Tax Act's NOL provisions, generated in tax years beginning after December 31, 2017.

 

December 31, 2017

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Deferred credits and other liabilities

$

143

 

$

33

 

$

78

 

$

23

 

$

49

 

$

11

 

$

6

 

$

(5

)

Capital lease obligations

49

 

14

 

2

 

 

Pension, post-retirement and other employee benefits

295

 

(17

)

111

 

44

 

60

 

14

 

18

 

(4

)

Progress Energy merger purchase accounting adjustments(a)

536

 

Tax credits and NOL carryforwards

4,527

 

234

 

402

 

156

 

143

 

25

 

216

 

70

 

Regulatory liabilities and deferred credits

222

 

65

 

61

 

Investments and other assets

 

 

 

 

 

 

1

 

18

 

Other

73

 

10

 

1

 

4

 

 

 

 

 

Valuation allowance

(519

)

(14

)

 

 

 

Total deferred income tax assets

5,104

 

496

 

578

 

227

 

252

 

115

 

243

 

140

 

Investments and other assets

(1,419

)

(849

)

(470

)

(289

)

(187

)

 

(14

)

 

Accelerated depreciation rates

(9,216

)

(3,060

)

(2,803

)

(1,583

)

(1,257

)

(896

)

(966

)

(697

)

Regulatory assets and deferred debits, net

(1,090

)

 

(807

)

(238

)

(569

)

 

(188

)

 

Other

 

 

 

 

 

 

 

(7

)

Total deferred income tax liabilities

(11,725

)

(3,909

)

(4,080

)

(2,110

)

(2,013

)

(896

)

(1,168

)

(704

)

Net deferred income tax liabilities

$

(6,621

)

$

(3,413

)

$

(3,502

)

$

(1,883

)

$

(1,761

)

$

(781

)

$

(925

)

$

(564

)

(a) Primarily related to capital lease obligations and debt fair value adjustments.

On June 28, 2017, the North Carolina General Assembly amended N.C. Gen. Stat. 105-130.3, reducing the North Carolina corporate income tax rate from a statutory rate of 3.0 to 2.5 percent beginning January 1, 2019. Duke Energy recorded a net reduction of approximately $55 million to their North Carolina deferred tax liabilities in the second quarter of 2017. The significant majority of this deferred tax liability reduction was offset by recording a regulatory liability pending NCUC determination of the disposition of amounts related to Duke Energy Carolinas, Duke Energy Progress and Piedmont. The impact did not have a significant impact on the financial position, results of operation or cash flows of Duke Energy, Duke Energy Carolinas, Progress Energy or Duke Energy Progress.

 

 

 

 

 

UNRECOGNIZED TAX BENEFITS

The following tables present changes to unrecognized tax benefits.

 

Year Ended December 31, 2018

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Unrecognized tax benefits – January 1

$

25

 

$

5

 

$

5

 

$

5

 

$

5

 

$

1

 

$

1

 

$

3

 

Unrecognized tax benefits increases (decreases)

 

 

 

 

 

 

 

 

Gross decreases – tax positions in prior periods

(2

)

(1

)

 

 

(4

)

 

 

 

Gross increases – current period tax positions

7

 

2

 

4

 

1

 

2

 

 

 

1

 

Decreases due to settlements

(6

)

 

 

 

 

 

 

 

Total changes

(1

)

1

 

4

 

1

 

(2

)

 

 

1

 

Unrecognized tax benefits – December 31

$

24

 

$

6

 

$

9

 

$

6

 

$

3

 

$

1

 

$

1

 

$

4

 

 

 

 

Year Ended December 31, 2017

 

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Unrecognized tax benefits – January 1

$

17

 

$

1

 

$

2

 

$

2

 

$

4

 

$

4

 

$

 

$

 

Unrecognized tax benefits increases (decreases)

 

 

 

 

 

 

 

 

Gross increases – tax positions in prior periods

12

 

4

 

3

 

3

 

1

 

1

 

1

 

3

 

Gross decreases – tax positions in prior periods

(4

)

 

 

 

 

(4

)

 

 

Total changes

8

 

4

 

3

 

3

 

1

 

(3

)

1

 

3

 

Unrecognized tax benefits – December 31

$

25

 

$

5

 

$

5

 

$

5

 

$

5

 

$

1

 

$

1

 

$

3

 

 

 

Year Ended December 31, 2016

 

 

Duke

 

Duke

Duke

Duke

Duke

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Unrecognized tax benefits – January 1

$

88

 

$

72

 

$

1

 

$

3

 

$

 

$

 

$

1

 

Unrecognized tax benefits increases (decreases)

 

 

 

 

 

 

 

Gross increases – tax positions in prior periods

 

 

 

 

4

 

4

 

 

Gross decreases – tax positions in prior periods

(4

)

(4

)

(1

)

(1

)

 

 

 

Decreases due to settlements

(68

)

(67

)

 

 

 

 

(1

)

Reduction due to lapse of statute of limitations

1

 

 

2

 

 

 

 

 

Total changes

(71

)

(71

)

1

 

(1

)

4

 

4

 

(1

)

Unrecognized tax benefits – December 31

$

17

 

$

1

 

$

2

 

$

2

 

$

4

 

$

4

 

$

 

 

The following table includes additional information regarding the Duke Energy Registrants' unrecognized tax benefits at December 31, 2018. All Duke Energy Registrants do not anticipate a material increase or decrease in unrecognized tax benefits within the next 12 months.

 

December 31, 2018

 

 

Duke

 

Duke

Duke

Duke

Duke

 

 

Duke

Energy

Progress

Energy

Energy

Energy

Energy

 

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Ohio

Indiana

Piedmont

Amount that if recognized, would affect the

effective tax rate or regulatory liability(a)

$

21

 

$

6

 

$

9

 

$

6

 

$

3

 

$

1

 

$

1

 

$

4

 

Amount that if recognized, would be recorded as

a component of discontinued operations

2

 

 

 

 

 

 

 

 

(a) Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, Duke Energy Indiana and Piedmont are unable to estimate the specific amounts that would affect the effective tax rate versus the regulatory liability.

OTHER TAX MATTERS

The following tables include interest recognized in the Consolidated Statements of Operations and the Consolidated Balance Sheets.

 

Year Ended December 31, 2018

 

 

 

Duke

 

Duke

Progress

Energy

(in millions)

Energy

Energy

Progress

Net interest income recognized related to income taxes

$

2

 

$

 

$

 

Interest payable related to income taxes

3

 

1

 

1

 

 

 

Year Ended December 31, 2017

 

 

Duke

 

Duke

Duke

 

Duke

Energy

Progress

Energy

Energy

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Net interest income recognized related to income taxes

$

 

$

 

$

1

 

$

 

$

1

 

Net interest expense recognized related to income taxes

 

2

 

 

 

 

Interest payable related to income taxes

5

 

25

 

1

 

1

 

 

 

 

Year Ended December 31, 2016

 

 

Duke

 

Duke

Duke

 

Duke

Energy

Progress

Energy

Energy

(in millions)

Energy

Carolinas

Energy

Progress

Florida

Net interest income recognized related to income taxes

$

 

$

 

$

1

 

$

 

$

2

 

Net interest expense recognized related to income taxes

 

7

 

 

 

 

Interest payable related to income taxes

4

 

23

 

1

 

1

 

 

Piedmont recognized $1 million in net interest income related to income taxes in the Consolidated Statements of Operations for the year ended October 31, 2016.

Duke Energy and its subsidiaries are no longer subject to U.S. federal examination for years before 2015. With few exceptions, Duke Energy and its subsidiaries are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2015.

 

24. OTHER INCOME AND EXPENSES, NET

The components of Other income and expenses, net on the Consolidated Statements of Operations are as follows.

 

Year Ended December 31, 2018

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Interest income

$

20

 

 

$

1

 

 

$

18

 

 

$

1

 

 

$

18

 

 

$

7

 

 

$

9

 

 

$

1

 

AFUDC equity

221

 

 

73

 

 

104

 

 

57

 

 

47

 

 

11

 

 

32

 

 

 

Post in-service equity returns

15

 

 

9

 

 

5

 

 

5

 

 

 

 

1

 

 

 

 

 

Nonoperating income, other

143

 

 

70

 

 

38

 

 

24

 

 

21

 

 

4

 

 

4

 

 

13

 

Other income and expense, net

$

399

 

 

$

153

 

 

$

165

 

 

$

87

 

 

$

86

 

 

$

23

 

 

$

45

 

 

$

14

 

 

 

Year Ended December 31, 2017

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

 

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

 

 

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

 

Piedmont

Interest income

$

13

 

 

$

2

 

 

$

6

 

 

$

2

 

 

$

5

 

 

$

6

 

 

$

8

 

 

$

 

AFUDC equity

237

 

 

106

 

 

92

 

 

47

 

 

45

 

 

11

 

 

28

 

 

 

Post in-service equity returns

40

 

 

28

 

 

12

 

 

12

 

 

 

 

 

 

 

 

 

Nonoperating income, other

218

 

 

63

 

 

99

 

 

54

 

 

46

 

 

6

 

 

11

 

 

(11

)

Other income and expense, net

$

508

 

 

$

199

 

 

$

209

 

 

$

115

 

 

$

96

 

 

$

23

 

 

$

47

 

 

$

(11

)

 

 

Year Ended December 31, 2016

 

 

 

Duke

 

 

 

Duke

 

Duke

 

Duke

 

Duke

 

Duke

 

Energy

 

Progress

 

Energy

 

Energy

 

Energy

 

Energy

(in millions)

Energy

 

Carolinas

 

Energy

 

Progress

 

Florida

 

Ohio

 

Indiana

Interest income

$

21

 

 

$

4

 

 

$

4

 

 

$

3

 

 

$

2

 

 

$

5

 

 

$

6

 

AFUDC equity

200

 

 

102

 

 

76

 

 

50

 

 

26

 

 

6

 

 

16

 

Post in-service equity returns

67

 

 

55

 

 

12

 

 

12

 

 

 

 

 

 

 

Nonoperating income, other

175

 

 

53

 

 

94

 

 

67

 

 

35

 

 

 

 

4

 

Other income and expense, net(a)

$

463

 

 

$

214

 

 

$

186

 

 

$

132

 

 

$

63

 

 

$

11

 

 

$

26

 

 

(a) Amounts for Piedmont for the two months ended December 31, 2016, and for the year ended October 31, 2016, were not material.

 

 

 

25. SUBSEQUENT EVENTS

For information on subsequent events related to the adoption of the new lease accounting standard, regulatory matters, commitments and contingencies and debt and credit facilities, see Notes 1, 4, 5 and 6, respectively.



Name of Respondent:

Duke Energy Ohio, Inc.
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)
5,030,433,803
3,153,189,130
1,553,882,234
323,362,439
4
UtilityPlantInServicePropertyUnderCapitalLeases
Property Under Capital Leases
50,429,583
5,672,328
39,181,133
5,576,122
5
UtilityPlantInServicePlantPurchasedOrSold
Plant Purchased or Sold
6
UtilityPlantInServiceCompletedConstructionNotClassified
Completed Construction not Classified
1,430,196,896
789,304,881
603,531,813
37,360,202
7
UtilityPlantInServiceExperimentalPlantUnclassified
Experimental Plant Unclassified
8
UtilityPlantInServiceClassifiedAndUnclassified
TOTAL Utility Plant (Total of lines 3 thru 7)
6,511,060,282
3,948,166,339
2,196,595,180
366,298,763
9
UtilityPlantLeasedToOthers
Leased to Others
10
UtilityPlantHeldForFutureUse
Held for Future Use
7,751,545
7,751,545
11
ConstructionWorkInProgress
Construction Work in Progress
280,022,162
217,938,656
53,451,656
8,631,850
12
UtilityPlantAcquisitionAdjustment
Acquisition Adjustments
13
UtilityPlantAndConstructionWorkInProgress
TOTAL Utility Plant (Total of lines 8 thru 12)
6,798,833,989
4,173,856,540
2,250,046,836
374,930,613
14
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Accumulated Provisions for Depreciation, Amortization, & Depletion
1,876,961,779
1,091,677,548
(a)
645,424,771
(c)
139,859,460
15
UtilityPlantNet
Net Utility Plant (Total of lines 13 and 14)
4,921,872,210
3,082,178,992
1,604,622,065
235,071,153
16
DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract
DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17
AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract
In Service:
18
DepreciationUtilityPlantInService
Depreciation
1,721,924,316
1,028,371,409
613,919,321
79,633,586
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
155,029,553
63,298,229
31,505,449
60,225,875
22
DepreciationAmortizationAndDepletionUtilityPlantInService
TOTAL In Service (Total of lines 18 thru 21)
1,876,953,869
1,091,669,638
645,424,770
139,859,461
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
7,910
7,910
29
AmortizationUtilityPlantHeldForFutureUse
Amortization
30
DepreciationAndAmortizationUtilityPlantHeldForFutureUse
TOTAL Held for Future Use (Total of lines 28 and 29)
7,910
7,910
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)
1,876,961,779
1,091,677,548
(b)
645,424,771
(d)
139,859,460


Name of Respondent:

Duke Energy Ohio, Inc.
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: AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Duplicate fact discrepancy. Schedule: 200 - Schedule - Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization and Depletion, Row: 33, Column: d, Value: 645424770
(b) Concept: AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Duplicate fact discrepancy. Schedule: 200 - Schedule - Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization and Depletion, Row: 33, Column: d, Value: 645424770
(c) Concept: AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Duplicate fact discrepancy. Schedule: 200 - Schedule - Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization and Depletion, Row: 33, Column: f, Value: 139859461
(d) Concept: AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Duplicate fact discrepancy. Schedule: 200 - Schedule - Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization and Depletion, Row: 33, Column: f, Value: 139859461

Name of Respondent:

Duke Energy Ohio, Inc.
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
3
FranchiseAndConsentsAbstract
302 Franchise and Consents
4
MiscellaneousIntangiblePlantAbstract
303 MiscellaneousIntangiblePlant
40,318,933
7,852,815
6,559
48,165,189
5
IntangiblePlantRollforwardAbstract
Total Intangible Plant (Total of lines 2 thru 4)
40,318,933
7,852,815
6,559
48,165,189
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
12
OtherLandAndLandRightsRollforwardAbstract
325.5 Other Land and Land Rights
13
GasWellStructuresRollforwardAbstract
326 Gas Well Structures
14
FieldCompressorStationStructuresRollforwardAbstract
327 Field Compressor Station Structures
15
FieldMeasuringAndRegulatingStationStructuresRollforwardAbstract
328 Field Measuring and Regulating Station Structures
16
OtherStructuresRollforwardAbstract
329 Other Structures
17
ProducingGasWellsWellConstructionRollforwardAbstract
330 Producing Gas Wells-Well Construction
18
ProducingGasWellsWellEquipmentRollforwardAbstract
331 Producing Gas Wells-Well Equipment
19
FieldLinesRollforwardAbstract
332 Field Lines
20
FieldCompressorStationEquipmentRollforwardAbstract
333 Field Compressor Station Equipment
21
FieldMeasuringAndRegulatingStationEquipmentRollforwardAbstract
334 Field Measuring and Regulating Station Equipment
22
DrillingAndCleaningEquipmentRollforwardAbstract
335 Drilling and Cleaning Equipment
23
PurificationEquipmentNaturalGasProductionPlantRollforwardAbstract
336 Purification Equipment
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
27
NaturalGasProductionAndGatheringPlantAbstract
Total Production and Gathering Plant (Total of lines 8 thru 26)
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)
40
ManufacturedGasProductionPlantAbstract
Manufactured Gas Production Plant (Submit supplementary information in a footnote)
18,347,135
1,691,284
903,628
19,134,791
41
NaturalGasProductionPlantAndManufacturedGasProductionPlantRollforwardAbstract
Total Production Plant (Total of lines 39 and 40)
18,347,135
1,691,284
903,628
19,134,791
42
NaturalGasStorageAndProcessingPlantAbstract
NATURAL GAS STORAGE AND PROCESSING PLANT
43
UndergroundStoragePlantAbstract
Underground storage plant
44
LandRollforwardAbstract
350.1 Land
45
RightsOfWayNaturalGasStorageAndProcessingPlantRollforwardAbstract
350.2 Rights-of-Way
46
StructuresAndImprovementsUndergroundStoragePlantRollforwardAbstract
351 Structures and Improvements
47
WellsRollforwardAbstract
352 Wells
48
StorageLeaseholdsAndRightsRollforwardAbstract
352.1 Storage Leaseholds and Rights
49
ReservoirsRollforwardAbstract
352.2 Reservoirs
50
NonrecoverableNaturalGasRollforwardAbstract
352.3 Non-recoverable Natural Gas
51
LinesRollforwardAbstract
353 Lines
52
CompressorStationEquipmentUndergroundStoragePlantRollforwardAbstract
354 Compressor Station Equipment
53
MeasuringAndRegulatingEquipmentUndergroundStoragePlantRollforwardAbstract
355 Measuring and Regulating Equipment
54
PurificationEquipmentUndergroundStoragePlantRollforwardAbstract
356 Purification Equipment
55
OtherEquipmentUndergroundStoragePlantRollforwardAbstract
357 Other Equipment
56
AssetRetirementCostsForUndergroundStoragePlantRollforwardAbstract
358 Asset Retirement Costs for Underground Storage Plant
57
UndergroundStoragePlantRollforwardAbstract
Total Underground Storage Plant (Total of lines 44 thru 56)
58
OtherStoragePlantAbstract
Other Storage Plant
59
LandAndLandRightsOtherStoragePlantRollforwardAbstract
360 Land and Land Rights
60
StructuresAndImprovementsOtherStoragePlantRollforwardAbstract
361 Structures and Improvements
61
GasHoldersRollforwardAbstract
362 Gas Holders
62
PurificationEquipmentOtherStoragePlantRollforwardAbstract
363 Purification Equipment
63
LiquefactionEquipmentRollforwardAbstract
363.1 Liquefaction Equipment
64
VaporizingEquipmentRollforwardAbstract
363.2 Vaporizing Equipment
65
CompressorEquipmentOtherStoragePlantRollforwardAbstract
363.3 Compressor Equipment
66
MeasuringAndRegulatingEquipmentOtherStoragePlantRollforwardAbstract
363.4 Measuring and Regulating Equipment
67
OtherEquipmentOtherStoragePlantRollforwardAbstract
363.5 Other Equipment
68
AssetRetirementCostsForOtherStoragePlantRollforwardAbstract
363.6 Asset Retirement Costs for Other Storage Plant
69
OtherStoragePlantRollforwardAbstract
Total Other Storage Plant (Total of lines 58 thru 68)
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)
82
TransmissionPlantAbstract
TRANSMISSION PLAN
83
LandAndLandRightsGasTransmissionPlantRollforwardAbstract
365.1 Land and Land Rights
84
RightsOfWayGasTransmissionPlantRollforwardAbstract
365.2 Rights-of-Way
85
StructuresAndImprovementsGasTransmissionPlantRollforwardAbstract
366 Structures and Improvements
86
MainsGasTransmissionPlantRollforwardAbstract
367 Mains
87
CompressorStationEquipmentGasTransmissionPlantRollforwardAbstract
368 Compressor Station Equipment
88
MeasuringAndRegulatingStationEquipmentRollforwardAbstract
369 Measuring and Regulating Station Equipment
89
CommunicationEquipmentTransmissionRollforwardAbstract
370 Communication Equipment
90
OtherEquipmentGasTransmissionPlantRollforwardAbstract
371 Other Equipment
91
AssetRetirementCostsForTransmissionPlantTransmissionPlantRollforwardAbstract
372 Asset Retirement Costs for Transmission Plant
92
TransmissionPlantRollforwardAbstract
Total Transmission Plant (Total of line 81 thru 91)
93
DistributionPlantAbstract
DISTRIBUTION PLANT
94
LandAndLandRightsGasDistributionPlantRollforwardAbstract
374 Land and Land Rights
10,290,343
1,360,543
114,584
11,536,302
95
StructuresAndImprovementsGasDistributionPlantRollforwardAbstract
375 Structures and Improvements
18,459,114
334,692
61,317
18,732,489
96
MainsGasDistributionPlantRollforwardAbstract
376 Mains
1,249,783,352
33,637,593
10,767,211
1,272,653,734
97
CompressorStationEquipmentGasDistributionPlantRollforwardAbstract
377 Compressor Station Equipment
98
MeasuringAndRegulatingStationEquipmentGeneralRollforwardAbstract
378 Measuring and Regulating Station Equipment-General
34,200,342
23,166,868
3,391,491
2,364,543
51,611,176
99
MeasuringAndRegulatingStationEquipmentCityGateCheckStationsRollforwardAbstract
379 Measuring and Regulating Station Equipment-City Gate
1,021,636
370,235
124,141
2,364,543
3,632,273
100
ServicesRollforwardAbstract
380 Services
549,776,689
34,349,155
2,021,458
582,104,386
101
MetersRollforwardAbstract
381 Meters
37,916,410
3,668,229
1,482,043
40,102,596
102
MeterInstallationsRollforwardAbstract
382 Meter Installations
27,772,221
1
649,341
27,122,879
103
HouseRegulatorsRollforwardAbstract
383 House Regulators
22,786,320
116,133
157,783
22,744,670
104
HouseRegulatoryInstallationsRollforwardAbstract
384 House Regulator Installations
16,889,144
16,889,144
105
IndustrialMeasuringAndRegulatingStationEquipmentRollforwardAbstract
385 Industrial Measuring and Regulating Station Equipment
3,553,148
1
3,207
3,549,942
106
OtherPropertyOnCustomersPremisesRollforwardAbstract
386 Other Property on Customers' Premises
107
OtherEquipmentGasDistributionPlantRollforwardAbstract
387 Other Equipment
1,435,275
3,045
1,432,230
108
AssetRetirementCostsForDistributionPlantDistributionPlantRollforwardAbstract
388 Asset Retirement Costs for Distribution Plant
12,554,394
88,221
462,643
13,105,258
109
DistributionPlantRollforwardAbstract
Total Distribution Plant (Total of lines 94 thru 108)
1,986,438,388
97,091,669
18,312,978
2,065,217,079
110
GeneralPlantAbstract
GENERAL PLANT
111
LandAndLandRightsRollforwardAbstract
389 Land and Land Rights
112
StructuresAndImprovementsRollforwardAbstract
390 Structures and Improvements
1,745,727
1
2,139
1,743,587
113
OfficeFurnitureAndEquipmentRollforwardAbstract
391 Office Furniture and Equipment
2,496,340
1,109,532
389,379
3,216,493
114
TransportationEquipmentRollforwardAbstract
392 Transportation Equipment
3,174,051
7,620
9,037
3,172,634
115
StoresEquipmentRollforwardAbstract
393 Stores Equipment
116
ToolsShopAndGarageEquipmentRollforwardAbstract
394 Tools, Shop, and Garage Equipment
11,147,488
1,608,218
329,527
12,426,179
117
LaboratoryEquipmentRollforwardAbstract
395 Laboratory Equipment
10,908
1,396
9,512
118
PowerOperatedEquipmentRollforwardAbstract
396 Power Operated Equipment
66,838
66,838
119
CommunicationEquipmentRollforwardAbstract
397 Communication Equipment
35,703,670
7,700,889
3,651
43,400,908
120
MiscellaneousEquipmentRollforwardAbstract
398 Miscellaneous Equipment
41,970
41,970
121
GeneralPlantExcludingOtherTangiblePropertyAndAssetRetirementCostsForGeneralPlantRollforwardAbstract
Subtotal (Total of lines 111 thru 120)
54,320,154
10,493,096
735,129
64,078,121
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)
54,320,154
10,493,096
735,129
64,078,121
125
GasPlantInServiceAndCompletedConstructionNotClassifiedGasRollforwardAbstract
Total (Accounts 101 and 106)
2,099,424,610
117,128,864
19,958,294
2,196,595,180
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)
2,099,424,610
117,128,864
19,958,294
2,196,595,180


Name of Respondent:

Duke Energy Ohio, Inc.
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
2009 Bank of America Leasing & Capital
Meters
1,604,213
2
2010 Bank of America Leasing & Capital
Meters
732,798
45
Total
2,337,011


Name of Respondent:

Duke Energy Ohio, Inc.
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:

Duke Energy Ohio, Inc.
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:

Duke Energy Ohio, Inc.
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
DISTRIBUTION PLANT
2
GAS DISTRIBUTION LINES EXTEND C314V FEED
12,791,045
3
LARGE MEASURING & REGULATING STATIONS
9,845,225
4
MAINS BLANKET GAS DISTRIBUTION LINES
2,933,418
5
GAS DISTRIBUTION LINES
2,466,536
6
OHIO GAS LINES PUBLIC IMPROVEMENTS
2,175,549
7
REAL ESTATE OHIO GAS DELIVERY
1,921,918
8
FERNALD SOUTH STATION 453
1,257,621
9
GAS FEEDER LINE- SCHEDULED DIGS
1,082,626
10
PROJECTS LESS THAN $1 MILLION
6,154,165
11
TOTAL DISTRIBUTION PLANT $40,628,103
12
GENERAL PLANT
13
GAS CONSTRUCTION PROJECTS ALLOCATIONS
1,098,416
14
PROJECTS LESS THAN $1 MILLION
725,122
15
TOTAL GENERAL PLANT $1,823,538
16
INTANGIBLE PLANT
17
CUSTOMER CONNECT FUNDING PROJECT
3,491,405
18
IT DEMAND WORK FUNDING PROJECT
2,636,662
19
PROJECTS LESS THAN $1 MILLION
1,170,424
20
TOTAL INTANGIBLE PLANT $7,928,491
21
PRODUCTION PLANT
22
EASTERN PROPANE PLANT MAINTENANCE WORK
1,735,940
23
GAS DISTRIBUTION LINES
1,641,730
24
PROJECTS LESS THAN $1 MILLION
22,482
25
TOTAL PRODUCTION PLANT $3,400,152
26
TRANSMISSION PLANT
27
PROJECTS LESS THAN $1 MILLION
301,372
28
TOTAL TRANSMISSION PLANT $301,372
45
TOTAL
53,451,656


Name of Respondent:

Duke Energy Ohio, Inc.
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
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
Gas Plant In Service


Name of Respondent:

Duke Energy Ohio, Inc.
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.

1. CONSTRUCTION OVERHEAD COSTS INCLUDE ENGINEERING AND SUPERVISORY SALARIES,

ADMINISTRATIVE AND GENERAL SALARIES AND ASSOCIATED PAYROLL TAXES AND BENEFITS AND

EMPLOYEE EXPENSES.

 

IN GENERAL, IF ENGINEERS, SUPERVISORS, AND CLERICAL EMPLOYEES DEVOTE ALL OR SUBSTANTIALLY

ALL OF THEIR TIME TO CAPITAL CONSTRUCTION PROJECTS, THE SALARIES AND RELATED EXPENSES ARE

CHARGED DIRECTLY TO THE SPECIFIC CAPITAL CONSTRUCTION PROJECTS.

 

FOR POWER DELIVERY, CONSTRUCTION OVERHEAD COSTS ARE CHARGED TO THE ALLOCATION POOLS AND

FROM THERE TRANSFERRED TO THE SPECIFIC CAPITAL CONSTRUCTION PROJECTS WHERE THE LABOR

(INTERNAL AND CONTRACT) WAS CHARGED DURING THE MONTH.

 

2. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) IS APPLIED TO THE TOTAL

CONSTRUCTION EXPENDITURES, LESS CERTAIN EXCLUSIONS, ON JOBS UNDER CONSTRUCTION. EFFECTIVE

JULY 1, 1982, THE RESPONDENT ADOPTED THE PRACTICE OF UPDATING THE AFUDC RATE MONTHLY, AS

AUTHORIZED BY THE FEDERAL ENERGY REGULATORY COMMISSION IN A LETTER DATED MAY 27, 1982. THE

AVERAGE AFUDC RATE FOR 2018 WAS 6.53%. THE MONTHLY RATE DOES NOT INCLUDE A REDUCTION FOR

THE INCOME TAX EFFECT ON THE COST OF DEBT.

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
d
(4) Preferred Stock
P
p
(5) Common Equity
C
c
(6) Total Capitaization
(7) Average Construction Work in Progress Balance
W
2. Gross Rate for Borrowed Funds s(S/W) + d[(D/(D+P+C)) (1-(S/W))] -
3. Rate for Other Funds [1-(S/W)] [p(P/(D+P+C)) + c(C/(D+P+C))] -
4. Weighted Average Rate Actually Used for the Year:
(a) Rate for Borrowed Funds -
(b) Rate for Other Funds -

Name of Respondent:

Duke Energy Ohio, Inc.
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
592,788,564
592,788,564
2 Depreciation Provisions for Year, Charged to
3
DepreciationExpenseExcludingAdjustments
(403) Depreciation Expense
45,050,881
45,050,881
4
DepreciationExpenseForAssetRetirementCosts
(403.1) Depreciation Expense for Asset Retirement Costs
5
ExpensesOfGasPlantLeasedToOthers
(413) Expense of Gas Plant Leased to Others
6
TransportationExpensesClearing
Transportation Expenses - Clearing
271,455
271,455
7
OtherClearingAccounts
Other Clearing Accounts
8
OtherAccounts
Other Clearing (Specify) (footnote details):
9.1
12,164,133
(a)
12,164,133
10
DepreciationProvision
TOTAL Deprec. Prov. for Year (Total of lines 3 thru 8)
57,486,469
57,486,469
11 Net Charges for Plant Retired:
12
BookCostOfRetiredPlant
Book Cost of Plant Retired
(b)
19,380,645
(e)
19,380,645
13
CostOfRemovalOfPlant
Cost of Removal
(c)
12,321,225
(f)
12,321,225
14
SalvageValueOfRetiredPlant
Salvage (Credit)
9,488
9,488
15
NetChargesForRetiredPlant
TOTAL Net Chrgs for Plant Ret. (Total of lines 12 thru 14)
(d)
31,711,358
(g)
31,711,358
16
Other Debit or Credit Items (Describe in footnote details)
17.1
(h)
4,644,354
(i)(j)
4,644,354
18
Book Cost of Asset Retirement Costs
19
Balance End of Year (Total of lines 1,10,15,16 and 18)
613,919,321
613,919,321
Section B. BALANCES AT END OF YEAR ACCORDING TO FUNCTIONAL CLASSIFICATIONS
21
AccumulatedDepreciationProductionsManufacturedGas
Productions-Manufactured Gas
9,574,309
9,574,309
22
AccumulatedDepreciationProductionAndGatheringNaturalGas
Production and Gathering-Natural Gas
23
AccumulatedDepreciationProductsExtractionNaturalGas
Products Extraction-Natural Gas
24
AccumulatedDepreciationUndergroundGasStorage
Underground Gas Storage
25
AccumulatedDepreciationOtherStorage
Other Storage Plant
26
AccumulatedDepreciationBaseLoadLngTerminalingAndProcessingPlant
Base Load LNG Terminaling and Processing Plant
27
AccumulatedDepreciationTransmission
Transmission
28
AccumulatedDepreciationDistribution
Distribution
586,276,298
586,276,298
29
AccumulatedDepreciationGeneral
General
18,068,714
18,068,714
30
AccumulatedProvisionForDepreciationOfGasUtilityPlant
TOTAL (Total of lines 21 thru 29)
613,919,321
613,919,321


Name of Respondent:

Duke Energy Ohio, Inc.
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: OtherAccounts

 

SmartGrid Depreciation Deferral $ 11,926,260

ARO Gas Depreciation 261,095

Misc. Adjustment to tie (23,222)

Total $ 12,164,133

(b) Concept: BookCostOfRetiredPlant
Original value: -19380645
(c) Concept: CostOfRemovalOfPlant
Original value: -12321225
(d) Concept: NetChargesForRetiredPlant
Original value: -31711358
(e) Concept: BookCostOfRetiredPlant
Original value: -19380645
(f) Concept: CostOfRemovalOfPlant
Original value: -12321225
(g) Concept: NetChargesForRetiredPlant
Original value: -31711358
(h) Concept: OtherAdjustmentsToAccumulatedDepreciation
Original value: -4644354
(i) Concept: OtherAdjustmentsToAccumulatedDepreciation

 

Common Utility Plant Provision $ (4,646,904)

Misc. Transfers/Adjustments 2,550

Total $ (4,644,354)

(j) Concept: OtherAdjustmentsToAccumulatedDepreciation
Original value: -4644354

Name of Respondent:

Duke Energy Ohio, Inc.
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
23,485,191
23,485,191
2
Gas Delivered to Storage
26,276,671
26,276,671
3
Gas Withdrawn from Storage
31,761,931
31,761,931
4
Other Debits and Credits
5
Balance at End of Year
17,999,931
17,999,931
6
Dth
5,864,178
5,864,178
7
Amount Per Dth
3.0695
3.0695


Name of Respondent:

Duke Energy Ohio, Inc.
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
Total Investment in Associated Companies
1
Total Other Investments
3,291,912
2,208,833
1
Total Temporary Cash Investments
1
123 NONE
2
124 CINCINNATI NEW MARKETS FUND
2,051,912
1,343,079
708,833
3
DATE ACQUIRED:04/20/05
4
124 MIDDLETOWN MOVING FORWARD
240,000
260,000
500,000
5
124 PORT OF GREATER CINCINNATI DEVELOPMENT AUTHORITY
1,000,000
1,000,000
6
136 NONE
7
TOTAL
3,291,912
260,000
1,343,079
2,208,833
8
Total Investments


Name of Respondent:

Duke Energy Ohio, Inc.
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
MIAMI POWER CORPORATION
09/30/1945
2
INVESTMENT AT COST
40,980
40,980
3
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS
180,497
129,140
309,637
4
PURCHASE ACCOUNTING GOODWILL ALLOCATION
6,553
6,553
5
ADVANCES-OPEN ACCOUNT
6,090
6,090
6
SUBTOTAL
234,120
129,140
363,260
7
DUKE ENERGY KENTUCKY, INC.
09/30/1945
8
INVESTMENT AT COST
27,397,284
27,397,284
9
DUKE ENERGY KENTUCKY, INC & PURCH ACCTG UNAPPROPRIATED
580,021,793
49,809,269
629,831,062
10
PURCHASE ACCOUNTING GOODWILL ALLOCATION
172,312,903
172,312,903
11
EQUITY INFUSION FROM DE OHIO TO DE KENTUCKY
15,000,000
35,000,000
50,000,000
12
CLEARING OF PURCHASE ACCOUNTING I&D & WORKERS COMP RESERVES
48,089
48,089
13
DUKE ENERGY KENTUCKY, INC AND PURCH ACCTG ADOPTION OF SFAS
164,697
164,697
14
DEFERRED TAX RECONCILIATION ADJUSTMENTS
880,824
880,824
15
TRANSFER OF GENERATION PLANTS (CALEB)
140,061,362
140,061,362
16
ADVANCES-OPEN ACCOUNT
4,015,807
4,015,807
17
CONTRIBUTION FROM PARENT TO FUND PENSION CONTRIBUTION
3,150,000
3,150,000
18
KENTUCKY DIVIDEND TO PARENT
250,000,000
250,000,000
19
SUBTOTAL
684,691,751
49,809,269
35,000,000
769,501,020
20
TRI-STATE IMPROVEMENT COMPANY
01/14/1964
21
INVESTMENT AT COST
25,000
25,000
22
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS
4,800,322
31,771
4,832,093
23
PURCHASE ACCOUNTING ADJUSTMENTS
2,690,629
2,690,629
24
PURCHASE ACCOUNTING GOODWILL ALLOCATION
168,780
168,780
25
ADVANCES-OPEN ACCOUNT
360,924
360,924
26
SUBTOTAL
1,892,549
31,771
1,924,320
27
KO TRANSMISSION COMPANY
04/11/1994
28
INVESTMENT AT COST
10
10
29
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS
8,987,262
2,209,908
11,197,170
30
DEFERRED TAX RECONCILIATION ADJUSTMENTS
43,869
43,869
31
ADVANCES-OPEN ACCOUNT
617,865
617,865
32
EQUITIZE BALANCE BETWEEN KO AND DUKE ENERGY OHIO
42,613,615
4,447,293
38,166,322
33
SUBTOTAL
52,262,621
2,209,908
4,447,293
50,025,236
34
DUKE ENERGY COMMERCIAL ASSET MANAGEMENT
35
INVESTMENT AT COST (FAYETTE, LEE, WASHINGTON, & HANGING ROCK)
04/01/2011
1,032,299,496
1,032,299,496
36
INVESTMENT AT COST (VERMILLION)
05/01/2011
138,400,465
138,400,465
37
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS
470,221,056
44,926
470,265,982
38
ADVANCES-OPEN ACCOUNT
426,962
426,962
39
DECAM DIVIDEND TO PARENT
902,000,000
902,000,000
40
DUKE ENERGY OHIO NON-NATIVE ALLOWANCE CONTRIBUTION
24,021,779
24,021,779
41
VERMILLION SALE TO DUKE ENERGY INDIANA
28,041,551
28,041,551
42
INVESTMENT AT BOOK VALUE (MIAMI FORT, ZIMMER, DICKS CREEK
05/01/2014
1,187,580,022
1,187,580,022
43
EQUITIZE BALANCE BETWEEN DECAM AND DUKE ENERGY OHIO
11,813,953
699,216
12,513,169
44
DISPOSITION
1,911,304,304
1,911,304,304
45
SUBTOTAL
23,417,878
44,926
699,216
24,162,020
46
BECKJORD
05/01/2014
47
INVESTMENT AT COST
969,213
969,213
48
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS
9,911,137
84,206,592
94,117,729
49
EQUITIZE BALANCE BETWEEN BECKJORD AND DUKE ENERGY OHIO
10,336,674
105,365,113
95,028,439
50
SUBTOTAL
21,217,024
84,206,592
105,365,113
58,503
40
TOTAL Cost of Account 123.1 $
Total
737,496,797
32,045,120
136,617,036
842,068,713


Name of Respondent:

Duke Energy Ohio, Inc.
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
2
PrepaidRents
Prepaid Rents
3
PrepaidTaxes
Prepaid Taxes
4
PrepaidInterest
Prepaid Interest
5
MiscellaneousPrepayments
Miscellaneous Prepayments
58,479
6
Prepayments
TOTAL
58,479


Name of Respondent:

Duke Energy Ohio, Inc.
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
NOT APPLICABLE
15
TOTAL


Name of Respondent:

Duke Energy Ohio, Inc.
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
NOT APPLICABLE
26
TOTAL


Name of Respondent:

Duke Energy Ohio, Inc.
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
Income Taxes
633,957
99,948,689
69,933,547
30,649,099
2
(a)
Accelerated Gas Main Replacement Program
17,593,383
1,845
443,416
17,151,812
3
(b)
SmartGrid
39,459,034
8,287,123
16,723,851
31,022,306
4
(c)
DEO Gas Construction Expenditure Program
23,438,107
27,320,934
4,506,550
46,252,491
5
(d)
Load Factor Adjustment Deferral-Asset
431,952
1,790
433,742
6
(e)
Ohio Distribution Decoupling Rider
10,428,118
6,190,626
890,787
15,727,957
7
(f)
MISO Hillcrest Project
782,346
3,343,814
2,561,468
8
(g)
MISO Transmission Expansion Projects
49,087,453
3,859,397
7,323,949
45,622,901
9
(h)
Alternative Energy Recovery Rider
326,077
1,106,194
1,301,145
131,126
10
(i)
Camera Costs AMRP- Reg Asset
1,325,987
1
995,103
330,885
11
(j)
Manufactured Gas Plant Reg Asset
90,887,082
37,143,752
28,678,449
99,352,385
12
(k)
MGP Reg Asset-Incurance Proceeds
18,913,725
2,082,940
33,279,811
50,110,596
13
(l)
Deferred DSM Costs
16,088,993
4,844,683
10,492,740
10,440,936
14
ARO Other Regulatory Assets
899,047
72,291
971,338
15
Gas ARO Other Regulatory Assets
18,032,451
1,682,082
19,714,533
16
(m)
Interest Rate Hedges
922,250
59,500
862,750
17
(n)
Ohio Electric Choice Supplier Website
353,125
2
353,127
18
(o)
NITS Deferral
16,127,605
7,425,164
875,279
22,677,490
19
(p)
Distribution Storm Rider-Asset
378,206
3,310,689
238,964
3,449,931
20
(q)
Bill Format CRES Logo Deferral
588,269
588,269
21
(r)
Vegetation Management Rider
10,000,000
10,000,000
22
(s)
Price Stabilization Rider
13,350,641
13,350,641
23
(t)
Opt-Out IT Modifications
243,122
243,122
24
(u)
Deferred Gas Integrity Costs
6,560,316
2,833,202
340,213
9,053,305
25
(v)
Accrued Pension Post Retire Purchase Accounting
27,349,024
1,600,968
25,748,056
26
Other Reg Assets- Gen Accounts
61,012,889
16,751,899
3,216,284
74,548,504
27
(w)
Pension Post Retire Accounting-FAS87 NQ
774,337
193,466
580,871
28
(x)
Pension Post Retire Purchase Accounting-FAS106
14,475,637
1,584,348
12,891,289
29
(y)
OH Electric Economic Competitive Fund
1,853,372
9,498,493
8,209,760
3,142,105
30
(z)
2012 DEO Gas Rate Case
74,250
81,000
6,750
40
TOTAL
381,212,664
255,712,437
194,746,686
442,178,415


FOOTNOTE DATA

(a) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

[image]

 

[image]

 

[image]

 

[image]

 

[image]

 

[image]

(b) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

All lines on footnote for column B are related to the following case numbers:

 

09-543-GE-UNC

08-920-EL-SSO

(c) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

All lines on footnote for column B are related to the following case numbers:

 

13-2417-GA-UNC

(d) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #11-3549-EL-SSO

(e) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #11-5905-EL-RDR

(f) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #11-2642-EL-RDR

(g) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #11-2642-EL-RDR

(h) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #11-3549-EL-SSO

(i) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #09-1097-GA-AAM

(j) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #09-712-GA-AAM

(k) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #09-712-GA-AAM

(l) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #06-0091-EL-UNC

(m) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #06-573-GA-AAM

 

Amortized over the life of various instruments.

(n) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #11-3549-EL-SSO

(o) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #11-2641-EL-RDR

(p) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #14-841-EL-SSO

(q) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #15-0855-EL-AAM

(r) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #17-32-EL-AIR

(s) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #17-32-EL-AIR

(t) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #14-1160-EL-UNC

(u) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #16-0387-GA-AAM

(v) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #06-573-GA-AAM

(w) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #06-573-GA-AAM

(x) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #06-573-GA-AAM

(y) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #11-6001-EL-RDR

(z) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

 

Case #12-1685-GA-AIR

(aa) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

 

Offsetting accounts are: 190, 236, 254, 255, 282, 283, 409, 410, 411

(ab) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

 

Offsetting account is 407.3 on all but the one highlighted on column A footnote (also offset by accou nt 930).

 

Order #01-1228-GA-AIR applies to all lines in footnote on column A.

(ac) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

[image]

[image]

(ad) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

[image]

(ae) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

 

Offsetting accounts are: 182.3, 232, 253

(af) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

 

Offsetting accounts are: 143, 146, 182.3, 232, 253, 456, 457, 561

(ag) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

 

Offsetting accounts are: 254, 407.3

(ah) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

 

Offsetting accounts are: 182.3, 228, 253, 407.3, 925

(ai) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

 

Offsetting accounts are: 131, 142, 143, 146, 182.3, 186, 228, 232, 235, 242, 253, 442, 456, 557, 561, 571, 920, 921, 923, 930

(aj) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

 

Offsetting accounts are: 107, 557, 874, 923

(ak) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

 

Offsetting accounts are: 128, 146, 182.3, 926

(al) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

 

Offsetting accounts are: 128, 182.3, 228, 253, 254, 926

(am) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

 

Offsetting accounts are: 146, 228, 254, 926


Name of Respondent:

Duke Energy Ohio, Inc.
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
Goodwill - PA
746,918,647
746,918,647
2
Other Miscellaneous Items
329,199
55,686,160
48,845,099
7,170,260
3
Vacation Accrual
3,211,492
511,318
3,722,810
4
Deferred Compensation
3,191,119
89,801
176,038
3,104,882
5
Cincinnati Zoo Naming Right
40,000
8,938
36,438
12,500
6
(Amort 5/1/2009-4/30/2019)
7
Accum Expenses - Debt
5,260
5,260
8
AHFS Accts for MWGen Assets
31
14
45
9
Accrued Pension Post Retirement
886,345
886,345
10
FAS 158
11
Economic Development Program
1,254,119
1,254,119
12
Ohio Excise Tax
14
14
13
Indirect Overhead Allocation
518,576
55,843,497
56,471,701
1,146,780
14
Pool - Undistributed
39
Miscellaneous Work in Progress
40
TOTAL
755,317,622
112,139,728
107,669,740
759,787,610


Name of Respondent:

Duke Energy Ohio, Inc.
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: DecreaseInMiscellaneousDeferredExpenseAccountCharged

 

Other Miscellaneous Items - Contra Accounts: 107, 108, 142, 143, 146, 172, 232, 236, 254, 408, 561, 742, 807, 874, 879, 880, 887, 892, 894, 930

(b) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

 

Indirect Overhead Allocation Pool - Undistributed - Contra Accounts: 105, 107, 108, 121, 143, 146, 154, 163, 183, 185, 232, 253, 408, 416, 417, 426, 454, 489, 506, 511, 524, 531, 549, 553, 560, 561, 562, 563, 566, 567, 569, 570, 571, 572, 573, 581, 582, 583, 584, 586, 587, 588, 589, 590, 591, 592, 593, 594, 595, 596, 597, 598, 717, 735, 742, 807, 850, 863, 870, 871, 874, 875, 876, 878, 879, 880, 887, 889, 892, 893, 894, 901, 902, 903, 908, 920, 921, 923, 926, 928, 930, 931, 932, 935, 999


Name of Respondent:


Duke Energy Ohio, Inc.
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
105,719,293
2,888,950
22,325,644
2,069
5,178
8,610,638
116,548,458
3
Gas
66,274,214
464,325
6,785,956
216
45
1,115,327
73,711,001
4
Other (Define)
5
Total (Total of lines 2 thru 4)
171,993,507
3,353,275
29,111,600
2,285
5,223
8,610,638
1,115,327
190,259,459
6
Other (Specify)
429,594
5,656
1,188
73,853
1,064,861
1,416,134
7
TOTAL Account 190 (Total of lines 5 thru 6)
172,423,101
3,358,931
29,112,788
2,285
5,223
8,684,491
2,180,188
191,675,593
8
Classification of TOTAL
9
Federal Income Tax
167,123,471
3,244,999
28,449,965
1,042
261
9,003,811
2,622,082
185,945,927
10
State Income Tax
5,299,630
113,932
662,823
1,243
4,962
319,320
441,894
5,729,666
11
Local Income Tax


Name of Respondent:

Duke Energy Ohio, Inc.
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
762,136,231
6
Preferred Stock (Account 204)
7
8
9
10
Total
Historical Data
11
COMMON STOCK
120,000,000
8.5
89,663,086
762,136,231
12
TOTAL COMMON STOCK (ACCT 201)
120,000,000
89,663,086
762,136,231
13
PREFERRED STOCK
14
TOTAL PREFERRED STOCK (ACCT 204)
15
Total


Name of Respondent:

Duke Energy Ohio, Inc.
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
Historical Data
1
ACCOUNT 202 - NONE
2
ACCOUNT 203 - NONE
3
ACCOUNT 205 - NONE
4
ACCOUNT 206 - NONE
5
ACCOUNT 207 - NONE
6
ACCOUNT 212 - NONE
40
Total


Name of Respondent:

Duke Energy Ohio, Inc.
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
Donations Received from Stockholders (Account 208)
19.2
IncreasesDecreasesInOtherPaidInCapital
Balance: Beginning of Year
1,506,928,418
19.3
IncreasesDecreasesInOtherPaidInCapital
Subtotal Balance: End of Year
1,506,928,418
19.4
IncreasesDecreasesInOtherPaidInCapital
Reduction in Par or Stated Value of Capital Stock (Account 209)
19.5
IncreasesDecreasesInOtherPaidInCapital
Gain on Resale of Cancellation of Required Capital Stock (Account 210)
19.6
IncreasesDecreasesInOtherPaidInCapital
Miscellaneous Paid-in-Capital (Account 211)
19.7
IncreasesDecreasesInOtherPaidInCapital
Balance: Beginning of Year
1,162,987,294
19.8
IncreasesDecreasesInOtherPaidInCapital
Equitization related to sale of Beckjord
105,365,114
19.9
IncreasesDecreasesInOtherPaidInCapital
Subtotal Balance: End of Year
1,268,352,408
20
OtherPaidInCapitalDetail
Ending Balance Amount
40
OtherPaidInCapital
Total
2,775,280,826


Name of Respondent:

Duke Energy Ohio, Inc.
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)
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)
29
Total


Name of Respondent:

Duke Energy Ohio, Inc.
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.

 

There was no new financing activity during 2018.








Name of Respondent:

Duke Energy Ohio, Inc.
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
1,100,000,000
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
550,000,000
Long Term Debt (Historical Data)
1
Account 221- First Mortgage Bonds
2
(a)
5.45% First Mortgage Bonds Due 2019
03/23/2009
04/01/2019
450,000,000
5.45
24,525,000
3
3.80% First Mortgage Bonds due 2023
09/06/2013
09/01/2023
300,000,000
3.8
11,400,000
4
3.70% First Mortgage Bonds due 2046
06/23/2016
06/15/2046
350,000,000
3.7
12,950,000
5
Subtotal Account 221
1,100,000,000
48,875,000
6
Account 222 & 223- None
7
Account 224- Notes Payable
8
6.90% Unsecured Debentures due in 2025
06/01/1995
06/01/2025
150,000,000
6.9
10,350,000
9
5.40% Debentures due in 2033
06/16/2003
06/15/2033
200,000,000
5.4
10,800,000
10
5.375% debentures due in 2033
06/16/2003
06/15/2033
200,000,000
5.375
10,750,000
11
Subtotal Account 224
550,000,000
31,900,000
12
(b)
SEE FOOTNOTE
13
OCI Amortization
59,500
14
(c)
Treasury Bonds
440,165
15
(d)
Account 430
40 TOTAL
1,650,000,000
81,274,665


Name of Respondent:

Duke Energy Ohio, Inc.
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: ClassOfSeriesOfObligationAndNameOfStockExchange

 

Footnote for line 2, 4, 6, 13, 15, 17 Column (i):

 

Redemption price of Debenture is based on the present value of the future interest and principle payments discounted at a rate equal to the yield of US government securities with a maturity similar to the Debentures plus a certain spread. This spread is presented in column i and is shown as basis points. The calculated Redemption Price can never be less than $100.

(b) Concept: ClassOfSeriesOfObligationAndNameOfStockExchange

 

On September 23, 2016, Duke Energy Corporation filed a Shelf Registration Statement providing for the registration for the issuance of public securities at Duke Energy Corporation, Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana, Duke Energy Progress and Duke Energy Florida. The registration statements became effective as of the filing date and have no amount limitation for Duke Energy Corporation and the other registrants. The authorizations are for approximately 3 years and will provide "Well Known Seasoned Issuer" (WKSI) status for all Duke Energy registrants. In January 2017, Duke Energy amended its Form S-3 to add Piedmont as a registrant and included in the amendment a prospectus for Piedmont under which it may issue debt securities in the same manner as other Duke Energy Registrants.

 

The long-term financing authority, PUCO Case No. 15-539-GE-AIS, to issue securities in the form of Secured and Unsecured notes and Capital leases was approved on 6/17/2015 and expires on 6/30/2016. The order provides authorization to issue up to $600 million of first mortgage bonds, senior and junior unsecured debentures, or other forms of unsecured indebtedness. Additionally, the authorization provides for the issuance of up $100 million of capital leases. Also, the authorization provides the authority to use interest rate hedges to help manage interest rate risk.

 

The long-term financing authority, PUCO Case No. 16-637-GE-AIS, to issue securities in the form of Secured and Unsecured notes and Capital leases was approved on 6/15/2016 and expires on 6/30/2017. The order provides authorization to issue up to $600 million of first mortgage bonds, senior and junior unsecured debentures, or other forms of unsecured indebtedness. Additionally, the authorization provides for the issuance of up $100 million of capital leases. Also, the authorization provides the authority to use interest rate hedges to help manage interest rate risk. The June 2016 debt issuance is included in the $600 million authorization.

 

The long-term financing authority, PUCO Case No. 16-637-GE-AIS, to issue securities in the form of Secured and Unsecured notes and Capital leases was approved on 6/15/2016 and expires on 6/30/2017. The order provides authorization to issue up to $600 million of first mortgage bonds, senior and junior unsecured debentures, or other forms of unsecured indebtedness. Additionally, the authorization provides for the issuance of up $100 million of capital leases. Also, the authorization provides the authority to use interest rate hedges to help manage interest rate risk. The June 2016 debt issuance is included in the $600 million authorization.

(c) Concept: ClassOfSeriesOfObligationAndNameOfStockExchange

 

The following Pollution Control Bonds Series were repurchased back in 2014 and are now classified as Treasury Bonds: 1995A, 1995B, 2002A, 2002B, 2004A, 2004B, 2007A, 2007B.

 

The amounts reflected represent insurance fees associated with the listed treasury bonds.

(d) Concept: ClassOfSeriesOfObligationAndNameOfStockExchange

 

The interest expense on Account 430 is related to short-term intercompany moneypool, so it is not disclosed on this form.


Name of Respondent:

Duke Energy Ohio, Inc.
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
UNAMORTIZED EXPENSE
2
(a)
6.9% UNSECURED DEBENTURES DUE 6/01/25
150,000,000
2,871,122
06/01/1995
06/01/2025
410,084
55,292
354,792
3
(b)
5.45% FIRST MORTGAGE BONDS DUE 4/1/19
450,000,000
2,174,657
03/23/2009
04/01/2019
279,630
223,704
55,926
4
(c)
3.80% FIRST MORTGAGE BONDS DUE 09/01/23
300,000,000
1,683,500
09/06/2013
09/01/2023
982,857
173,446
809,411
5
(d)
5.40% DEBENTURES DUE 6/15/33
200,000,000
1,295,647
06/16/2003
06/15/2033
428,576
27,729
400,847
6
(e)
5.375% DEBENTURES DUE 6/15/33
200,000,000
840,299
06/16/2003
06/15/2033
369,121
23,883
345,238
7
(f)
3.70% FIRST MORTGAGE BONDS DUE 06/15/46
350,000,000
3,226,833
06/23/2016
06/15/2046
3,013,346
88,732
106,408
2,995,670
8
FIRST MORTGAGE BONDS - 7.20%
9
(g)(h)
MASTER CREDIT FACILITY
11/18/2011
03/16/2023
1,478,582
178,704
320,467
1,336,819
10
(i)
SUBTOTAL ACCOUNT 181
6,962,196
267,436
930,929
6,298,703
11
FIRST MORTGAGE BONDS - 7.20%
12
UNAMORTIZED PREMIUM
13
(j)
PURCH ACCTG - 5.40% DEBENTURES DUE 6/15/33
200,000,000
2,590,117
04/01/2006
06/15/2033
1,469,191
95,060
1,374,131
14
PURCH ACCTG - 6.90% UNSECURED DEBENTURES DUE 6/1/25
150,000,000
6,459,047
04/01/2006
06/01/2025
2,500,842
337,192
2,163,650
15
SUBTOTAL ACCOUNT 225
3,970,033
432,252
3,537,781
16
UNAMORTIZED DISCOUNT
17
6.9% UNSECURED DEBENTURES DUE 2025
150,000,000
975,000
06/01/1995
06/01/2025
241,230
32,535
208,695
18
5.45% DEBENTURES DUE 4/1/19
450,000,000
180,000
03/23/2009
04/01/2019
22,442
17,962
4,480
19
5.40% DEBENTURES DUE 6/15/33
200,000,000
35,366,184
06/16/2003
06/15/2033
18,224,734
1,179,170
17,045,564
20
5.375% DEBENTURES DUE 6/15/33
200,000,000
17,312,591
06/16/2003
06/15/2033
9,772,748
632,312
9,140,436
21
3.80% FIRST MORTGAGE BONDS DUE 9/01/23
300,000,000
99,000
09/06/2013
09/01/2023
56,177
9,914
46,263
22
3.70% FIRST MORTGAGE BONDS DUE 06/15/46
350,000,000
8,285,500
06/23/2016
06/15/2046
8,026,446
282,070
7,744,376
23
SUBTOTAL ACCOUNT 226
36,343,777
2,153,963
34,189,814


Name of Respondent:

Duke Energy Ohio, Inc.
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: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 3, Column: a, Value: FIRST MORTGAGE BONDS - 9.70%, 10-1/8%
(b) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 4, Column: a, Value: FIRST MORTGAGE BONDS - 10.20% DATED DECEMBER 1, 1990 DUE DECEMBER 1, 2020
(c) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 5, Column: a, Value: FIRST MORTGAGE BONDS - 8.95% SERIES
(d) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 6, Column: a, Value: FIRST MORTGAGE BONDS - 8-1/2%
(e) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 7, Column: a, Value: FIRST MORTGAGE BONDS - 7.20%
(f) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 8, Column: a, Value: DEBENTURES - 8.28% JR SB
(g) Concept: DesignationOfLongTermDebt

 

In January 2018, Duke Energy extended the termination date of substantially all of its existing $8 billion Master Credit Facility capacity from March 16, 2022, to March 16, 2023. In May 2018, Duke Energy completed the extension process with 100 percent of all commitments to the Master Credit Facility extending to March 16, 2023. The Duke Energy Registrants, excluding Progress Energy (Parent), have borrowing capacity under the Master Credit Facility up to specified sublimits for each borrower.

 

Duke Energy Ohio has a $300 million borrowing limit as of December 31, 2018.

(h) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 10, Column: a, Value: OAQD BONDS 2001 A SERIES
(i) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 12, Column: a, Value: TOTAL ACCOUNT 189
(j) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 16, Column: a, Value: TOTAL ACCOUNT 257

Name of Respondent:

Duke Energy Ohio, Inc.
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
UNAMORTIZED EXPENSE
2
(a)
6.9% UNSECURED DEBENTURES DUE 6/01/25
05/01/1995
200,000,000
101,694
48,014
3
(b)
5.45% FIRST MORTGAGE BONDS DUE 4/1/19
10/30/1995
4,000,000
79,454
52,212
4
(c)
3.80% FIRST MORTGAGE BONDS DUE 09/01/23
03/03/1997
100,000,000
82,930
61,964
5
(d)
5.40% DEBENTURES DUE 6/15/33
03/30/1998
100,000,000
66,072
51,913
6
(e)
5.375% DEBENTURES DUE 6/15/33
07/14/1999
34,500,000
26,227
21,666
7
(f)
3.70% FIRST MORTGAGE BONDS DUE 06/15/46
06/30/2003
100,000,000
777,112
673,498
8
FIRST MORTGAGE BONDS - 7.20%
10/01/2003
265,500,000
1,138,147
940,209
9
(g)(h)
MASTER CREDIT FACILITY
09/01/2010
12,100,000
363,776
340,432
10
(i)
SUBTOTAL ACCOUNT 181
816,100,000
2,635,412
2,189,908
11
FIRST MORTGAGE BONDS - 7.20%
07/14/1999
34,500,000
238,533
197,049
12
UNAMORTIZED PREMIUM
13
(j)
PURCH ACCTG - 5.40% DEBENTURES DUE 6/15/33
34,500,000
238,533
197,049
14
PURCH ACCTG - 6.90% UNSECURED DEBENTURES DUE 6/1/25
15
SUBTOTAL ACCOUNT 225
16
UNAMORTIZED DISCOUNT
17
6.9% UNSECURED DEBENTURES DUE 2025
18
5.45% DEBENTURES DUE 4/1/19
19
5.40% DEBENTURES DUE 6/15/33
20
5.375% DEBENTURES DUE 6/15/33
21
3.80% FIRST MORTGAGE BONDS DUE 9/01/23
22
3.70% FIRST MORTGAGE BONDS DUE 06/15/46
23
SUBTOTAL ACCOUNT 226


Name of Respondent:

Duke Energy Ohio, Inc.
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: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 3, Column: a, Value: FIRST MORTGAGE BONDS - 9.70%, 10-1/8%
(b) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 4, Column: a, Value: FIRST MORTGAGE BONDS - 10.20% DATED DECEMBER 1, 1990 DUE DECEMBER 1, 2020
(c) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 5, Column: a, Value: FIRST MORTGAGE BONDS - 8.95% SERIES
(d) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 6, Column: a, Value: FIRST MORTGAGE BONDS - 8-1/2%
(e) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 7, Column: a, Value: FIRST MORTGAGE BONDS - 7.20%
(f) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 8, Column: a, Value: DEBENTURES - 8.28% JR SB
(g) Concept: DesignationOfLongTermDebt

 

In January 2018, Duke Energy extended the termination date of substantially all of its existing $8 billion Master Credit Facility capacity from March 16, 2022, to March 16, 2023. In May 2018, Duke Energy completed the extension process with 100 percent of all commitments to the Master Credit Facility extending to March 16, 2023. The Duke Energy Registrants, excluding Progress Energy (Parent), have borrowing capacity under the Master Credit Facility up to specified sublimits for each borrower.

 

Duke Energy Ohio has a $300 million borrowing limit as of December 31, 2018.

(h) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 10, Column: a, Value: OAQD BONDS 2001 A SERIES
(i) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 12, Column: a, Value: TOTAL ACCOUNT 189
(j) Concept: DesignationOfLongTermDebt
Duplicate fact discrepancy. Schedule: 260 - Schedule - Unamortized Loss and Gain on Reacquired Debt (Account 189, 257), Row: 16, Column: a, Value: TOTAL ACCOUNT 257

Name of Respondent:

Duke Energy Ohio, Inc.
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)
175,820,388
2
Reconciling Items for the Year
3
4
Taxable Income Not Reported on Books
5
Contributions in Aid of Construction
13,617,631
8
13,617,631
9
Deductions Recorded on Books Not Deducted for Return
10
See Footnote for Details
(a)
351,307,599
13
351,307,599
14
Income Recorded on Books Not Included in Return
15
Equity in Earnings of Subsidiary
(b)
32,045,120
16
Allowance for Funds Used During Construction
13,692,682
17
Post In-Service Carrying Costs
(c)
1,335,755
18
(d)
19,688,193
19
Deductions on Return Not Charged Against Book Income
20
See Footnote for Details
(e)
402,747,630
26
402,747,630
27
Federal Tax Net Income
157,686,181
28
Show Computation of Tax:
29
Tax at @ 21%
33,114,098
30
NOLs
13,247,375
31
Prior Period Adjustments
6,388,202
32
Other
135,782
33
Total Federal Income Tax Provision
40,109,053


Name of Respondent:

Duke Energy Ohio, Inc.
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

 

[image]

(b) Concept: IncomeRecordedOnBooksNotIncludedInReturn
Original value: -32045120
(c) Concept: IncomeRecordedOnBooksNotIncludedInReturn
Original value: -1335755
(d) Concept: IncomeRecordedOnBooksNotIncludedInReturn
Original value: -19688193
(e) Concept: DeductionsOnReturnNotChargedAgainstBookIncome

 

[image]


Name of Respondent:

Duke Energy Ohio, Inc.
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 TAXES
2
INCOME TAXES
2,033,363
40,109,053
21,155,696
5,100,351
11,819,643
31,028,994
8,467,744
612,315
3
FEDERAL INSURANCE
181,404
6,169,871
3,875,573
2,315,061
160,641
4,071,079
2,098,792
4
UNEMPLOYMENT
914
29,677
25,464
3,234
1,892
20,761
8,915
5
HIGHWAY & FUEL
5,759
5,759
3,863
1,896
6
STATE TAXES
7
INCOME TAXES
29,591
700,012
150,081
149,612
670,890
544,897
137,272
17,843
8
UNEMPLOYMENT
2,206
20,383
21,298
1,290
14,331
6,053
9
SALES & USE
85,365
24,632
923,774
888,304
25,262
16,497
8,136
10
PROPERTY
517,583
374,810
892,393
374,810
11
EXCISE
12,118,199
101,783,411
101,258,613
12,642,997
74,083,260
27,700,151
12
OTHER TAXES
13
LOCAL PROPERTY
159,969,101
165,541,980
164,144,190
5,883,334
167,250,225
141,234,636
24,307,344
14
CINCINNATI FRANCHISE
6,620,507
926,065
926,065
6,620,507
926,065
15
OHIO COMMERCIAL
5,236,151
2,702,889
1,852,810
476,574
4,862,646
2,702,889
40
Total
172,196,174
318,339,278
294,039,161
1,273,194
195,223,094
254,614,278
62,720,031
1,004,968


Name of Respondent:

Duke Energy Ohio, Inc.
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
Vacation Entitlement Reserve
4,509,768
2
Contract Retentions
4,141,844
3
MISO MTEP Short Term Accruals
3,011,734
4
Provision for Incentive Ben Prog
2,420,385
5
Wages Payable Accrual
2,224,496
6
FAS 158 Liabilities
2,033,604
7
Severance Reserve/Accrual
1,678,715
8
Retirement Bank Accrual
1,549,534
9
Collateral Liab
327,500
10
OVEC/FE Reserve
292,059
11
Litigation Reserve Accrued - Account 0242650
200,000
12
Deferred Revenue Payable - Other
180,644
13
Solar Interconnect Deposits
37,295
14
Employee Other Insurance Deductions
29,222
45
Total
22,636,800


Name of Respondent:

Duke Energy Ohio, Inc.
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
Reserves - Mgp Sites FERC
46,541,000
28,414,005
28,730,505
46,857,500
2
MISO MTEP Accrual
46,000,955
8,393,065
2,096,208
39,704,098
3
Customer Choice Program - Deposit
3,563,500
77,000
769,358
4,255,858
4
Deferred Revenue
1,901,473
1,137,017
1,619,754
2,384,210
5
2016 Weatherization Programs
700,000
700,000
6
Accruals
7
Gas Refund and Recon. Adj.
241,096
300,695
277,772
218,173
8
- Due Customers
9
Misc Deferred Credits and Other
15,981
1,426
2,648
17,203
10
Postretirement Benefits Health
3,219
3,219
11
Care - DP&L/CSP Share
12
Pension Cost Adj.
156,555
156,555
13
- DP&L/CSP Share
14
Employee Postretirement Benefit
4,160
95
4,255
15
Cost - DP&L
45
TOTAL
99,113,181
38,479,858
33,503,719
94,137,042


Name of Respondent:

Duke Energy Ohio, Inc.
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: DecreaseInOtherDeferredCreditsContraAccount

 

Reserves - Mgp Sites FERC - Contra Accounts: 146, 182.3, 228.4, 232, 426, 874, 909, 910, 912, 920, 921, 923, 930

(b) Concept: DecreaseInOtherDeferredCreditsContraAccount

 

MISO MTEP Accrual - Contra Accounts: 143, 146, 182.3, 232, 456, 457, 561

(c) Concept: DecreaseInOtherDeferredCreditsContraAccount

 

Deferred Revenue - Contra Accounts: 146, 415, 557

(d) Concept: DecreaseInOtherDeferredCreditsContraAccount

 

Gas Refund & Recon. Adj. - Due Customers - Contra Accounts: 146, 182.3, 191, 805

(e) Concept: DecreaseInOtherDeferredCreditsContraAccount

 

Postretirement Benefits Health Care - DP&L/CSP Share - Contra Accounts: 102, 143, 146, 165, 232, 566

(f) Concept: DecreaseInOtherDeferredCreditsContraAccount

 

Pension Cost Adj. - DP&L/CSP Share - Contra Accounts: 102, 143, 146, 165, 232, 566

(g) Concept: DecreaseInOtherDeferredCreditsContraAccount

 

Employee Postretirement Benefit Cost - DP&L - Contra Accounts: 143, 165, 232, 408, 563, 566, 568, 570, 571, 925, 926


Name of Respondent:


Duke Energy Ohio, Inc.
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
453,914,358
53,511,674
38,245,421
39,283
61,844
22,997,758
492,155,808
3
Gas
227,750,224
32,048,152
15,997,805
6,370
1,800
3,734,210
240,070,931
4
Other (Define)
5
Total (Total of lines 2 thru 4)
681,664,582
85,559,826
54,243,226
45,653
63,644
22,997,758
3,734,210
732,226,739
6
Other (Specify)
18,099,292
736,824
3
3
46,300
11,546,843
5,861,925
7
TOTAL Account 282 (Total of lines 5 thru 6)
699,763,874
85,559,826
54,980,050
45,656
63,647
23,044,058
15,281,053
738,088,664
8
Classification of TOTAL
9
Federal Income Tax
692,825,562
82,889,887
52,094,051
43,569
40,010
19,619,481
16,281,021
726,963,417
10
State Income Tax
6,938,312
2,669,939
2,885,999
2,087
23,637
3,424,577
999,968
11,125,247
11
Local Income Tax


Name of Respondent:


Duke Energy Ohio, Inc.
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
25,787,692
12,810,874
3,375,520
2,080
437
820,794
34,403,895
3
Gas
37,147,002
2,983,638
5,749,517
16,866
34,364,257
4
Other (Define)
5
Total (Total of lines 2 thru 4)
62,934,694
15,794,512
9,125,037
2,080
437
837,660
68,768,152
6
Other (Specify)
720,403
246
1,170
721,330
2
1
7
TOTAL Account 283 (Total of lines 5 thru 6)
62,214,291
15,794,758
9,126,207
2,080
437
721,330
837,662
68,768,153
8
Classification of TOTAL
9
Federal Income Tax
60,542,256
15,503,814
8,812,303
437
721,330
774,044
67,180,616
10
State Income Tax
1,672,035
290,944
313,904
2,080
63,618
1,587,537
11
Local Income Tax


Name of Respondent:

Duke Energy Ohio, Inc.
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
Income Taxes
533,638,491
11,008,075,625
11,039,353,847
564,916,713
2
Supplier Cost Recovery Liability
15,079,392
11,245,215
12,996,218
16,830,395
3
Order #11-3549-EL-SSO
4
Bad Debt Expense Over Collection
4,571,072
1,261,741
2,018,968
5,328,299
5
Order #09-773-GA-UEX
6
Regulatory Liability - NQ/OPEB
11,071,717
142,740
1,542,546
12,471,523
7
Deferred DDR Regulatory Liability (BTR)
4,776,473
36,296,889
34,225,150
2,704,734
8
Order #11-5905-EL-RDR
9
Alternative Energy Recovery Rider
24,238,721
56,096,793
43,178,546
11,320,474
10
(Amortized in accordance with revenue rider)
11
Order #11-3549-EL-SSO
12
Distribution Storm Rider Liability
82,153
17,714
64,439
13
Order #14-841-EL-SSO
45
Total
593,458,019
11,113,136,717
11,133,315,275
613,636,577


Name of Respondent:

Duke Energy Ohio, Inc.
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: OtherRegulatoryLiabilityAccountOffsettingCredits

 

Offsetting accounts are: 182.3, 190, 236, 254, 255, 282, 283, 409, 410, 411

(b) Concept: OtherRegulatoryLiabilityAccountOffsettingCredits

 

Offsetting accounts are: 146, 182.3, 228, 926


Name of Respondent:

Duke Energy Ohio, Inc.
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)
934,934
12,715,493
12,715,493
2,289,788
20,190,339
20,190,339
3,139,585
23,003,573
23,003,573
2
Transportation of Gas for Others (489.2 and 489..3)
3
Rate Case #PRO-27
5,731
5,731
15,361
15,361
9,116
9,116
4
Rate FT
2,254,443
15,698,703
15,698,703
4,751,431
17,759,031
17,759,031
6,657,980
18,032,188
18,032,188
5
Rate IT
1,708,407
1,444,014
1,444,014
1,826,473
1,483,808
1,483,808
1,939,153
1,551,893
1,551,893
63
Total Transportation (Other than Gathering)
3,962,850
17,148,448
17,148,448
6,577,904
19,258,200
19,258,200
8,597,133
19,593,197
19,593,197
64
Storage (489.4)
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
Total Storage
91
Gathering (489.1)
92
Gathering-Firm
93
Gathering-Interruptible
94
Total Gathering (489.1)
95
Additional Revenues
96
Products Sales and Extraction (490-492)
97
Rents (493-494)
391,704
391,704
380,023
380,023
380,023
380,023
98
(495) Other Gas Revenues
255
255
5,248
5,248
6,278
6,278
99
(496) (Less) Provision for Rate Refunds
100
Total Additional Revenues
391,959
391,959
385,271
385,271
386,301
386,301
101
Total Operating Revenues (Total of Lines 1,63,90,94 & 100)
4,897,784
30,255,900
30,255,900
8,867,692
39,833,810
39,833,810
11,736,718
42,983,071
42,983,071


Name of Respondent:

Duke Energy Ohio, Inc.
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
142,973,897
152,347,651
142,973,897
152,347,651
12,608,650
12,424,145
2
CommercialAndIndustrialSalesAbstract
(481) Commercial and Industrial Sales
53,340,144
53,189,591
53,340,144
53,189,591
5,647,759
5,067,748
3
OtherSalesToPublicAuthoritiesAbstract
(482) Other Sales to Public Authorities
2,762,354
2,973,677
2,762,354
2,973,677
359,295
343,411
4
SalesForResaleAbstract
(483) Sales for Resale
5
InterdepartmentalSalesAbstract
(484) Interdepartmental Sales
210,921
189,750
210,921
189,750
37,908
33,095
6
IntracompanyTransfersAbstract
(485) Intracompany Transfers
7
ForfeitedDiscountsAbstract
(487) Forfeited Discounts
8
MiscellaneousServiceRevenuesAbstract
(488) Miscellaneous Service Revenues
319,837
327,042
319,837
327,042
9
RevenuesFromTransportationOfGasOfOthersThroughGatheringFacilitiesAbstract
(489.1) Revenues from Transportation of Gas of Others Through Gathering Facilities
10
RevenuesFromTransportationOfGasOfOthersThroughTransmissionFacilitiesAbstract
(489.2) Revenues from Transportation of Gas of Others Through Transmission Facilities
11
RevenuesFromTransportationOfGasOfOthersThroughDistributionFacilitiesAbstract
(489.3) Revenues from Transportation of Gas of Others Through Distribution Facilities
214,218,784
202,073,426
214,218,784
202,073,426
63,115,661
55,921,969
12
RevenuesFromStoringGasOfOthersAbstract
(489.4) Revenues from Storing Gas of Others
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
4,677,087
4,787,623
4,677,087
4,787,623
17
InterdepartmentalRentsAbstract
(494) Interdepartmental Rents
18
OtherGasRevenuesAbstract
(495) Other Gas Revenues
85,376
13,263
85,376
13,263
19
OperatingRevenuesBeforeProvisionForRateRefundsAbstract
Subtotal:
418,588,400
415,902,023
418,588,400
415,902,023
20
ProvisionForRateRefundsAbstract
(496) (Less) Provision for Rate Refunds
14,302,193
14,302,193
21
OperatingRevenuesAbstract
TOTAL
404,286,207
415,902,023
404,286,207
415,902,023


Name of Respondent:

Duke Energy Ohio, Inc.
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
NOT APPLICABLE


Name of Respondent:

Duke Energy Ohio, Inc.
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
NOT APPLICABLE


Name of Respondent:

Duke Energy Ohio, Inc.
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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25


Name of Respondent:

Duke Energy Ohio, Inc.
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
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
9
RevenuesFromPenaltiesEarnedPursuantToTariffProvisionsIncludingPenaltiesAssociatedWithCashOutSettlements
Revenues from Penalties earned Pursuant to Tariff Provisions, including Penalties Associated with Cash-out Settlements
10
RevenuesFromShipperSuppliedGas
Revenues from Shipper Supplied Gas
11
Other revenues (Specify):
12
Other revenues (Specify):
(a)
85,376
40
TOTAL
85,376


Name of Respondent:

Duke Energy Ohio, Inc.
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: OtherMiscellanousGasRevenues

 

Gas Losses Damaged Lines


Name of Respondent:

Duke Energy Ohio, Inc.
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
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
Total


Name of Respondent:

Duke Energy Ohio, Inc.
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)
(a)
4,672,867
4,032,490
4
NaturalGasProductionExpensesAbstract
B. Natural Gas Production
5
NaturalGasProductionAndGatheringPlantAbstract
B1. Natural Gas Production and Gathering
6
NaturalGasProductionAndGatheringOperationAbstract
Operation
7
OperationSupervisionAndEngineeringNaturalGasProductionAndGathering
750 Operation Supervision and Engineering
8
ProductionMapsAndRecords
751 Production Maps and Records
9
GasWellsExpenses
752 Gas Well Expenses
10
FieldLinesExpenses
753 Field Lines Expenses
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
14
PurificationExpensesNaturalGasProductionAndGathering
757 Purification Expenses
15
GasWellRoyalties
758 Gas Well Royalties
16
OtherExpensesNaturalGasProductionAndGathering
759 Other Expenses
17
RentsNaturalGasProductionAndGathering
760 Rents
18
ProductionOperationExpense
TOTAL Operation (Total of lines 7 thru 17)
19
NaturalGasProductionAndGatheringMaintenanceAbstract
Maintenance
20
MaintenanceSupervisionAndEngineeringNaturalGasProductionAndGathering
761 Maintenance Supervision and Engineering
21
MaintenanceOfStructuresAndImprovementsNaturalGasProductionAndGathering
762 Maintenance of Structures and Improvements
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
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)
30
ProductionOperationAndMaintenanceExpense
TOTAL Natural Gas Production and Gathering (Total of lines 18 and 29)
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
89,271,314
84,144,557
71
NaturalGasGasolinePlantOutletPurchases
802 Natural Gas Gasoline Plant Outlet Purchases
72
NaturalGasTransmissionLinePurchases
803 Natural Gas Transmission Line Purchases
73
NaturalGasCityGatePurchases
804 Natural Gas City Gate Purchases
74
LiquefiedNaturalGasPurchases
804.1 Liquefied Natural Gas Purchases
75
OtherGasPurchases
805 Other Gas Purchases
11,075,047
14,450,974
76
PurchasedGasCostAdjustments
(Less) 805.1 Purchases Gas Cost Adjustments
77
PurchasedGasOperationExpenses
TOTAL Purchased Gas (Total of lines 68 thru 76)
78,196,267
69,693,583
78
ExchangeGas
806 Exchange Gas
1,813,974
6,311,923
79
PurchasedGasExpensesAbstract
Purchased Gas Expenses
80
WellExpensePurchasedGas
807.1 Well Expense-Purchased Gas
81
OperationOfPurchasedGasMeasuringStations
807.2 Operation of Purchased Gas Measuring Stations
710,355
780,933
82
MaintenanceOfPurchasedGasMeasuringStations
807.3 Maintenance of Purchased Gas Measuring Stations
326,903
335,496
83
PurchasedGasCalculationsExpenses
807.4 Purchased Gas Calculations Expenses
84
OtherPurchasedGasExpenses
807.5 Other Purchased Gas Expenses
540,727
28,459
85
PurchasedGasExpenses
TOTAL Purchased Gas Expenses (Total of lines 80 thru 84)
1,577,985
1,144,888
86
GasWithdrawnFromStorageDebt
808.1 Gas Withdrawn from Storage-Debit
87
GasDeliveredToStorageCredit
(Less) 808.2 Gas Delivered to Storage-Credit
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
92
GasUsedForProductsExtractionCredit
811 Gas Used for Products Extraction-Credit
93
GasUsedForOtherUtilityOperationsCredit
812 Gas Used for Other Utility Operations-Credit
94
GasUsedInUtilityOperationCredit
TOTAL Gas Used in Utility Operations-Credit (Total of lines 91 thru 93)
95
OtherGasSupplyExpenses
813 Other Gas Supply Expenses
96
OtherGasSupplyExpensesOperation
TOTAL Other Gas Supply Exp. (Total of lines 77,78,85,86 thru 89,94,95)
77,960,278
77,150,394
97
ProductionExpenses
TOTAL Production Expenses (Total of lines 3, 30, 58, 65, and 96)
82,633,145
81,182,884
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
102
MapsAndRecords
815 Maps and Records
103
WellsExpenses
816 Wells Expenses
104
LinesExpenses
817 Lines Expense
105
CompressorStationExpenses
818 Compressor Station Expenses
106
CompressorStationFuelAndPowerUndergroundStorageExpenses
819 Compressor Station Fuel and Power
107
MeasuringAndRegulatingStationExpenses
820 Measuring and Regulating Station Expenses
108
PurificationExpensesUndergroundStorage
821 Purification Expenses
109
ExplorationAndDevelopment
822 Exploration and Development
110
GasLossesUndergroundStorageExpenses
823 Gas Losses
111
OtherExpensesUndergroundStorage
824 Other Expenses
112
StorageWellRoyalties
825 Storage Well Royalties
113
RentsUndergroundStorageExpenses
826 Rents
114
UndergroundStorageOperationExpenses
TOTAL Operation (Total of lines of 101 thru 113)
115
UndergroundStorageEpensesMaintenanceAbstract
Maintenance
116
MaintenanceSupervisionAndEngineeringUndergroundStorageExpenses
830 Maintenance Supervision and Engineering
117
MaintenanceOfStructuresAndImprovementsUndergroundStorageExpenses
831 Maintenance of Structures and Improvements
118
MaintenanceOfReservoirsAndWells
832 Maintenance of Reservoirs and Wells
119
MaintenanceOfLines
833 Maintenance of Lines
120
MaintenanceOfCompressorStationEquipmentUndergroundStorageExpenses
834 Maintenance of Compressor Station Equipment
121
MaintenanceOfMeasuringAndRegulatingStationEquipmentUndergroundStorageExpenses
835 Maintenance of Measuring and Regulating Station Equipment
122
MaintenanceOfPurificationEquipmentUndergroundStorageExpenses
836 Maintenance of Purification Equipment
123
MaintenanceOfOtherEquipmentUndergroundStorageExpenses
837 Maintenance of Other Equipment
124
UndergroundStorageMaintenanceExpenses
TOTAL Maintenance (Total of lines 116 thru 123)
125
UndergroundStorageExpenses
TOTAL Underground Storage Expenses (Total of lines 114 and 124)
126
OtherStorageExpensesAbstract
B. Other Storage Expenses
127
OtherStorageExpensesOperationAbstract
Operation
128
OperationSupervisionAndEngineeringOtherStorageExpenses
840 Operation Supervision and Engineering
129
OperationLaborAndExpenses
841 Operation Labor and Expenses
130
RentsOtherStorageExpenses
842 Rents
131
FuelOtherStorageExpenses
842.1 Fuel
132
PowerOtherStorageExpenses
842.2 Power
133
GasLossesOtherStorageExpenses
842.3 Gas Losses
134
OtherStorageOperationExpenses
TOTAL Operation (Total of lines 128 thru 133)
135
OtherStorageExpensesMaintenanceAbstract
Maintenance
136
MaintenanceSupervisionAndEngineeringOtherStorageExpenses
843.1 Maintenance Supervision and Engineering
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
142
MaintenanceOfCompressorEquipmentOtherStorageExpenses
843.7 Maintenance of Compressor Equipment
143
MaintenanceOfMeasuringAndRegulatingEquipmentOtherStorageExpenses
843.8 Maintenance of Measuring and Regulating Equipment
144
MaintenanceOfOtherEquipmentOtherStorageExpenses
843.9 Maintenance of Other Equipment
145
OtherStorageMaintenanceExpenses
TOTAL Maintenance (Total of lines 136 thru 144)
146
OtherStorageExpenses
TOTAL Other Storage Expenses (Total of lines 134 and 145)
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)
178
TransmissionExpensesAbstract
3. TRANSMISSION EXPENSES
179
TransmissionExpensesOperationAbstract
Operation
180
OperationSupervisionAndEngineeringGasTransmissionExpenses
850 Operation Supervision and Engineering
5,070
181
SystemControlAndLoadDispatchingGas
851 System Control and Load Dispatching
182
CommunicationSystemExpenses
852 Communication System Expenses
183
CompressorStationLaborAndExpensesTransmissionExpenses
853 Compressor Station Labor and Expenses
184
GasForCompressorStationFuel
854 Gas for Compressor Station Fuel
185
OtherFuelAndPowerForCompressorStations
855 Other Fuel and Power for Compressor Stations
186
MainsExpenses
856 Mains Expenses
187
MeasuringAndRegulatingStationExpensesTransmissionExpenses
857 Measuring and Regulating Station Expenses
188
TransmissionAndCompressionOfGasByOthers
858 Transmission and Compression of Gas by Others
189
OtherExpensesGasTransmission
859 Other Expenses
5,334
131
190
RentsGasTransmissionExpense
860 Rents
191
TransmissionOperationExpense
TOTAL Operation (Total of lines 180 thru 190)
10,404
131
192
TransmissionExpensesMaintenanceAbstract
Maintenance
193
MaintenanceSupervisionAndEngineeringGasTransmissionExpenses
861 Maintenance Supervision and Engineering
194
MaintenanceOfStructuresAndImprovementsTransmissionExpenses
862 Maintenance of Structures and Improvements
195
MaintenanceOfMainsTransmissionExpenses
863 Maintenance of Mains
157,843
196
MaintenanceOfCompressorStationEquipmentTransmissionExpenses
864 Maintenance of Compressor Station Equipment
197
MaintenanceOfMeasuringAndRegulatingStationEquipment
865 Maintenance of Measuring and Regulating Station Equipment
198
MaintenanceOfCommunicationEquipmentGasTransmission
866 Maintenance of Communication Equipment
199
MaintenanceOfOtherEquipmentTransmissionExpenses
867 Maintenance of Other Equipment
200
TransmissionMaintenanceExpensesGas
TOTAL Maintenance (Total of lines 193 thru 199)
157,843
201
TransmissionExpenses
TOTAL Transmission Expenses (Total of lines 191 and 200)
168,247
131
202
DistributionExpensesAbstract
4. DISTRIBUTION EXPENSES
203
DistributionExpensesOperationAbstract
Operation
204
OperationSupervisionAndEngineeringDistributionExpenses
870 Operation Supervision and Engineering
92
205
DistributionLoadDispatching
871 Distribution Load Dispatching
607,491
737,330
206
CompressorStationLaborAndExpenses
872 Compressor Station Labor and Expenses
207
CompressorStationFuelAndPowerDistributionExpenses
873 Compressor Station Fuel and Power
208
MainsAndServicesExpenses
874 Mains and Services Expenses
8,728,138
10,053,878
209
MeasuringAndRegulatingStationExpensesGeneral
875 Measuring and Regulating Station Expenses-General
34,084
38,740
210
MeasuringAndRegulatingStationExpensesIndustrial
876 Measuring and Regulating Station Expenses-Industrial
281,730
166,644
211
MeasuringAndRegulatingStationExpensesCityGateCheckStations
877 Measuring and Regulating Station Expenses-City Gas Check Station
212
MeterAndHouseRegulatorExpenses
878 Meter and House Regulator Expenses
6,784,842
5,077,737
213
CustomerInstallationsExpenses
879 Customer Installations Expenses
4,756,309
4,110,717
214
OtherExpensesGasDistribution
880 Other Expenses
6,981,891
8,068,363
215
RentsDistributionExpense
881 Rents
216
DistributionOperationExpensesGas
TOTAL Operation (Total of lines 204 thru 215)
28,174,577
28,253,409
217
DistributionExpensesMaintenanceAbstract
Maintenance
218
MaintenanceSupervisionAndEngineeringDistributionExpenses
885 Maintenance Supervision and Engineering
1
219
MaintenanceOfStructuresAndImprovementsDistributionExpenses
886 Maintenance of Structures and Improvements
220
MaintenanceOfMains
887 Maintenance of Mains
4,625,315
6,998,006
221
MaintenanceOfCompressorStationEquipment
888 Maintenance of Compressor Station Equipment
222
MaintenanceOfMeasuringAndRegulatingStationEquipmentGeneral
889 Maintenance of Measuring and Regulating Station Equipment-General
162,741
147,023
223
MaintenanceOfMeasuringAndRegulatingStationEquipmentIndustrial
890 Maintenance of Meas. and Reg. Station Equipment-Industrial
1,889
224
MaintenanceOfMeasuringAndRegulatingStationEquipmentCityGateCheckStations
891 Maintenance of Meas. and Reg. Station Equip-City Gate Check Station
225
MaintenanceOfServices
892 Maintenance of Services
277,228
238,285
226
MaintenanceOfMetersAndHouseRegulators
893 Maintenance of Meters and House Regulators
695,136
677,498
227
MaintenanceOfOtherEquipmentGasDistribution
894 Maintenance of Other Equipment
109,361
261,186
228
DistributionMaintenanceExpenseGas
TOTAL Maintenance (Total of lines 218 thru 227)
5,651,059
8,323,888
229
DistributionExpenses
TOTAL Distribution Expenses (Total of lines 216 and 228)
33,825,636
36,577,297
230
CustomerAccountsExpensesAbstract
5. CUSTOMER ACCOUNTS EXPENSES
231
CustomerAccountsExpensesOperationsAbstract
Operation
232
SupervisionCustomerAccountExpenses
901 Supervision
594,554
530,591
233
MeterReadingExpenses
902 Meter Reading Expenses
553,059
675,244
234
CustomerRecordsAndCollectionExpenses
903 Customer Records and Collection Expenses
12,149,809
10,394,645
235
UncollectibleAccounts
904 Uncollectible Accounts
3,189,368
4,934,345
236
MiscellaneousCustomerAccountsExpenses
905 Miscellaneous Customer Accounts Expenses
1,149
1,365
237
CustomerAccountExpenses
TOTAL Customer Accounts Expenses (Total of lines 232 thru 236)
16,487,939
16,536,190
238
CustomerServiceAndInformationalExpensesAbstract
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
239
CustomerServiceAndInformationalExpensesOperationAbstract
Operation
240
SupervisionCustomerServiceAndInformationExpenses
907 Supervision
241
CustomerAssistanceExpenses
908 Customer Assistance Expenses
638,205
605,806
242
InformationalAndInstructionalAdvertisingExpenses
909 Informational and Instructional Expenses
23,756
20,049
243
MiscellaneousCustomerServiceAndInformationalExpenses
910 Miscellaneous Customer Service and Informational Expenses
2,392,907
2,900,465
244
CustomerServiceAndInformationalExpenses
TOTAL Customer Service and Information Expenses (Total of lines 240 thru 243)
3,054,868
3,526,320
245
SalesExpensesAbstract
7. SALES EXPENSES
246
SalesExpenseOperationAbstract
Operation
247
SupervisionSalesExpense
911 Supervision
1,976
43
248
DemonstratingAndSellingExpenses
912 Demonstrating and Selling Expenses
372,041
213,113
249
AdvertisingExpenses
913 Advertising Expenses
17,469
26,595
250
MiscellaneousSalesExpenses
916 Miscellaneous Sales Expenses
5,936
251
SalesExpenses
TOTAL Sales Expenses (Total of lines 247 thru 250)
397,422
239,751
252
AdministrativeAndGeneralExpensesAbstract
8. ADMINISTRATIVE AND GENERAL EXPENSES
253
AdministrativeAndGeneralExpensesOperationAbstract
Operation
254
AdministrativeAndGeneralSalaries
920 Administrative and General Salaries
10,406,459
6,714,775
255
OfficeSuppliesAndExpenses
921 Office Supplies and Expenses
5,496,345
4,719,485
256
AdministrativeExpensesTransferredCredit
(Less) 922 Administrative Expenses Transferred-Credit
634
863
257
OutsideServicesEmployed
923 Outside Services Employed
10,008,787
5,147,687
258
PropertyInsurance
924 Property Insurance
267,625
372,154
259
InjuriesAndDamages
925 Injuries and Damages
513,622
1,325,891
260
EmployeePensionsAndBenefits
926 Employee Pensions and Benefits
(b)
6,138,051
6,190,302
261
FranchiseRequirements
927 Franchise Requirements
262
RegulatoryCommissionExpenses
928 Regulatory Commission Expenses
706,422
766,102
263
DuplicateChargesCredit
(Less) 929 Duplicate Charges-Credit
828,871
772,417
264
GeneralAdvertisingExpenses
930.1General Advertising Expenses
124,745
49,028
265
MiscellaneousGeneralExpenses
930.2Miscellaneous General Expenses
499,971
73,101
266
RentsAdministrativeAndGeneralExpense
931 Rents
1,504,475
1,930,191
267
AdministrativeAndGeneralOperationExpense
TOTAL Operation (Total of lines 254 thru 266)
34,838,265
26,517,162
268
MaintenanceAbstract
Maintenance
269
MaintenanceOfGeneralPlant
932 Maintenance of General Plant
405,070
17,423
270
AdministrativeAndGeneralExpenses
TOTAL Administrative and General Expenses (Total of lines 267 and 269)
35,243,335
26,534,585
271
OperationsAndMaintenanceExpensesGas
TOTAL Gas O&M Expenses (Total of lines 97,177,201,229,237,244,251, and 270)
171,810,592
164,597,158


Name of Respondent:

Duke Energy Ohio, Inc.
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: ManufacturedGasProduction

OPERATION:

 

2018 Q4

2017 Q4

 

Gas Boiler Labor

$ 20,725

$ 13,770

 

Other Power Expenses

38,764

31,750

 

Liquified Petroleum Gas Expense

246,111

262,381

 

Liquified Petroleum Gas

1,660,463

2,046,525

 

Misc. Production Expense

392,181

342,178

 

Gas Raw Material - Rents

330,558

564,521

 

Total Operation

$ 2,688,802

$ 3,261,125

MAINTENANCE:

 

 

 

 

Production Equipment

1,984,065

771,365

 

Total Maintenance

$ 1,984,065

$ 771,365

 

 

 

 

Total Manufactured Gas Production

$ 4,672,867

$ 4,032,490

(b) Concept: EmployeePensionsAndBenefits
Duplicate fact discrepancy. Schedule: 352 - Schedule - Employee Pensions and Benefits (Account 926), Row: 40, Column: b, Value: 17389568

Name of Respondent:

Duke Energy Ohio, Inc.
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
Texas Gas Transmission - Zone 4 NNS
339,559
65,405
339,559
65,405
2
Duke Energy Ohio Enhanced Firm Balancing Service
1,474,416
13,196
1,474,416
13,196
25
Total
1,813,975
52,209
1,813,975
52,209


Name of Respondent:


Duke Energy Ohio, Inc.
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
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
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Total


Name of Respondent:

Duke Energy Ohio, Inc.
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:

Duke Energy Ohio, Inc.
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
NONE
25
Total


Name of Respondent:

Duke Energy Ohio, Inc.
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.
83,563
2
ferc:ExperimentalAndGeneralResearchExpensesAbstract
Experimental and general research expenses
2a
ferc:GasResearchInstituteExpense
a. Gas Research Institute (GRI)
2b
ferc:OtherExperimentalAndGeneralResearchExpenses
b. Other
3,252
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
Business and Service Company Support
54,096
6
Dues and Subscriptions to Various Organizations
245,673
7
Director's Fees and Expenses
81,514
8
Shareholder's Communications/Systems
424
9
Account Analysis Reconciliation Adjustments
139,641
25
TOTAL
499,971


Name of Respondent:


Duke Energy Ohio, Inc.
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
4,352,590
4,352,590
2
Production plant, manufactured gas
410,699
410,699
3
Production and Gathering Plant
4
Products extraction plant
5
Underground Gas Storage Plant (footnote details)
6
Other storage plant
7
Base load LNG terminaling and processing plant
8
Transmission Plant
9
Distribution plant
37,443,029
37,443,029
10
General Plant (footnote details)
2,550,249
946,997
3,497,246
11
Common plant-gas
4,646,904
394,426
5,041,330
12
Total
45,050,881
5,694,013
50,744,894


Name of Respondent:


Duke Energy Ohio, Inc.
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
10
11
12
13
14
15


Name of Respondent:

Duke Energy Ohio, Inc.
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
696,069
11
Account 426.2 - Life Insurance
12
13
14
15
TOTAL Account 426.2 - Life Insurance
167,834
16
Account 426.3 - Penalties
17
18
19
20
TOTAL Account 426.3 - Penalties
42
21
Account - 426.4 Expenditues for Certain Civic, Political, and Related Activities
22
23
24
25
TOTAL Account 426.3 - Penalties
1,666,045
26
Account 426.5 - Other Deductions
27
28
29
30
TOTAL Account 426.5 - Other Deductions
11,678,744
31
Account 430 - Interest on Debt to Associated Companies
32
33
34
35
TOTAL Account 430 - Interest on Debt to Associated Companies
2,055,484
36
Account 431 - Other Interest Expense
37
38
39
40
TOTAL Account 431 - Other Interest Expense
2,544,138
1
Account 421 - Loss on Disposal of Property
61,153
2
Account 426.1 - Donations
3
Community Involvement
169,064
4
State Marketing
188,646
5
Customer Assistance Programs
158,729
6
Items Under Threshold
179,630
7
Account 426.2 - Life Insurance
8
Life Insurance Expense
167,834
9
Account 426.3 - Penalties
10
Items Under Threshold
42
11
Account 426.4 - Expenditures
12
Civic, Political & Related Activities
1,666,045
13
Account 426.5 - Other Deductions
14
Sale of A/R Fees
10,949,348
15
Inc Deduction-Other Inc & Exp
700,000
16
Items Under Threshold
29,396
17
Total Account 426
14,269,887
18
Account 430 - Interest on Debt to Associated Companies
19
Money Pool - Duke Energy Ohio to Duke Energy Corporation
1,542,924
20
Money Pool - Duke Energy Ohio to Duke Energy Florida
396,154
21
Money Pool - Duke Energy Ohio to Duke Energy Progress
62,347
22
Money Pool - Duke Energy Ohio to Duke Energy Carolinas
38,969
23
Money Pool - Duke Energy Ohio to Piedmont Natural Gas
15,003
24
Money Pool - Duke Energy Ohio to Duke Energy Kentucky
87
25
Total Account 430
2,055,484
26
Account 431 - Other Interest Expense
27
Interest - Assigned from Service Company
1,180,134
28
Customer Service Deposit @ 3% Annum
850,220
29
Credit Facility
386,371
30
Capital Meter Lease Interest
72,303
31
Certified Retail Energy Suppliers
20,648
32
Deferred Compensation for Board of Directors
18,601
33
Items Under Threshold
15,861
34
Total Account 431
2,544,138


Name of Respondent:

Duke Energy Ohio, Inc.
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
Regulatory Commission Fees
2
Gas Related
3
Public Utilities Commission of Ohio (PUCO)
540,029
540,029
Gas
540,029
4
Ohio Consumers' Counsel
85,393
85,393
Gas
85,393
5
Electric Related
6
Public Utilities Commission of Ohio
1,359,756
1,359,756
Electric
1,359,756
7
Ohio Consumers' Counsel
215,014
215,014
Electric
216,014
8
PUCO - Division of Forecasting
111,228
111,228
Electric
111,228
9
Public Utilities Commission of Ohio
10
Case No. 12-2685-GA-AIR
11
Request for Rate Increase - Gas
81,000
81,000
74,250
Gas
81,000
6,750
12
Public Utilities Commission of Ohio
13
Case No. 17-0032-EL-AIR
14
Request for Rate Increase - Electric (1)
Electric
301,430
15
(1) The deferred expenses from the Request for
16
Rate Increase, Case No. 17-0032-EL-AIR, are
17
deferred in FERC account 186.
25
TOTAL
2,311,420
81,000
2,392,420
74,250
2,393,420
294,680


Name of Respondent:

Duke Energy Ohio, Inc.
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
3,322,026
2
Pensions - other
3,295,520
3
Post-retirement benefits other than pensions (PBOP)
2,262,336
4
Post-employment benefit plans
762,111
5
Other (Specify)
6
Medical and Dental
5,836,072
7
Life Insurance
56,623
8
Service/Safety Awards
41,520
9
Other Work/Family Benefits/Tuition
51,410
10
Allocated S&E
2,793,413
11
Benefits Distribution
10,352,326
12
Other
847,089
40
Total
(a)
6,138,051


Name of Respondent:

Duke Energy Ohio, Inc.
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
Duplicate fact discrepancy. Schedule: 352 - Schedule - Employee Pensions and Benefits (Account 926), Row: 40, Column: b, Value: 17389568

Name of Respondent:


Duke Energy Ohio, Inc.
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
411,706
4,501,060
345,551
5,258,317
5
SalariesAndWagesElectricOperationDistribution
Distribution
6,106,494
6,682,872
899,571
13,688,937
6
SalariesAndWagesElectricCustomerAccounts
Customer Accounts
1,301,156
8,844,087
713,590
10,858,833
7
SalariesAndWagesElectricCustomerServiceAndInformational
Customer Service and Informational
80
638,157
44,892
683,129
8
SalariesAndWagesElectricSales
Sales
9
SalariesAndWagesElectricOperationAdministrativeAndGeneral
Administrative and General
1,088,375
24,028,506
1,766,657
26,883,538
10
SalariesAndWagesElectricOperation
TOTAL Operation (Total of lines 3 thru 9)
8,907,811
44,694,682
3,770,261
57,372,754
11
SalariesAndWagesElectricMaintenanceAbstract
Maintenance
12
SalariesAndWagesElectricMaintenanceProduction
Production
177,644
2,261,128
2,438,772
13
SalariesAndWagesElectricMaintenanceTransmission
Transmission
526,250
1,522,675
2,048,925
14
SalariesAndWagesElectricMaintenanceDistribution
Distribution
7,405,840
3,661,993
11,067,833
15
SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral
Administrative and General
19,949
2,844
22,793
16
SalariesAndWagesElectricMaintenance
TOTAL Maintenance (Total of lines 12 thru 15)
8,129,683
7,448,640
15,578,323
17
SalariesAndWagesElectricOperationAndMaintenanceAbstract
Total Operation and Maintenance
18
SalariesAndWagesElectricProduction
Production (Total of lines 3 and 12)
177,644
2,261,128
2,438,772
19
SalariesAndWagesElectricTransmission
Transmission (Total of lines 4 and 13)
937,956
6,023,735
345,551
7,307,242
20
SalariesAndWagesElectricDistribution
Distribution (Total of lines 5 and 14)
13,512,334
10,344,865
899,571
24,756,770
21
SalariesAndWagesElectricCustomerAccounts
Customer Accounts (line 6)
1,301,156
8,844,087
713,590
10,858,833
22
SalariesAndWagesElectricCustomerServiceAndInformational
Customer Service and Informational (line 7)
80
638,157
44,892
683,129
23
SalariesAndWagesElectricSales
Sales (line 8)
24
SalariesAndWagesElectricAdministrativeAndGeneral
Administrative and General (Total of lines 9 and 15)
1,108,324
24,031,350
1,766,657
26,906,331
25
SalariesAndWagesElectricOperationAndMaintenance
TOTAL Operation and Maintenance (Total of lines 18 thru 24)
17,037,494
52,143,322
3,770,261
72,951,077
26
SalariesAndWagesGasAbstract
Gas
27
SalariesAndWagesGasOperationAbstract
Operation
28
SalariesAndWagesGasOperationProductionManufacturedGas
Production - Manufactured Gas
107,309
32,796
2,716
142,821
29
SalariesAndWagesGasOperationProductionNaturalGas
Production - Natural Gas(Including Exploration and Development)
30
SalariesAndWagesGasOperationOtherGasSupply
Other Gas Supply
23,530
951,302
18,894
993,726
31
SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing
Storage, LNG Terminaling and Processing
32
SalariesAndWagesGasOperationTransmission
Transmission
33
SalariesAndWagesGasOperationDistribution
Distribution
4,133,619
7,169,660
219,079
11,522,358
34
SalariesAndWagesGasCustomerAccounts
Customer Accounts
904,216
5,439,057
122,945
6,466,218
35
SalariesAndWagesGasCustomerServiceAndInformational
Customer Service and Informational
703,834
13,642
717,476
36
SalariesAndWagesGasSales
Sales
37
SalariesAndWagesGasOperationAdministrativeAndGeneral
Administrative and General
606,989
7,924,400
165,355
8,696,744
38
SalariesAndWagesGasOperation
TOTAL Operation (Total of lines 28 thru 37)
5,775,663
22,221,049
542,631
28,539,343
39
SalariesAndWagesGasMaintenanceAbstract
Maintenance
40
SalariesAndWagesGasMaintenanceProductionManufacturedGas
Production - Manufactured Gas
162,136
169,153
331,289
41
SalariesAndWagesGasMaintenanceProductionNaturalGas
Production - Natural Gas(Including Exploration and Development)
42
SalariesAndWagesGasMaintenanceOtherGasSupply
Other Gas Supply
43
SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing
Storage, LNG Terminaling and Processing
44
SalariesAndWagesGasMaintenanceTransmission
Transmission
45
SalariesAndWagesGasMaintenanceDistribution
Distribution
1,928,292
1,288,221
3,216,513
46
SalariesAndWagesGasMaintenanceAdministrativeAndGeneral
Administrative and General
774
795
1,569
47
SalariesAndWagesGasMaintenance
TOTAL Maintenance (Total of lines 40 thru 46)
2,091,202
1,458,169
3,549,371
49
SalariesAndWagesGasOperationAndMaintenanceAbstract
Total Operation and Maintenance
50
SalariesAndWagesGasProductionManufacturedGas
Production - Manufactured Gas (Total of lines 28 and 40)
269,445
201,949
2,716
474,110
51
SalariesAndWagesGasProductionNaturalGas
Production - Natural Gas (Including Expl. and Dev.)(ll. 29 and 41)
52
SalariesAndWagesGasOtherGasSupply
Other Gas Supply (Total of lines 30 and 42)
23,530
951,302
18,894
993,726
53
SalariesAndWagesGasStorageLngTerminalingAndProcessing
Storage, LNG Terminaling and Processing (Total of ll. 31 and 43)
54
SalariesAndWagesGasTransmission
Transmission (Total of lines 32 and 44)
55
SalariesAndWagesGasDistribution
Distribution (Total of lines 33 and 45)
6,061,911
8,457,881
219,079
14,738,871
56
SalariesAndWagesGasCustomerAccounts
Customer Accounts (Total of line 34)
904,216
5,439,057
122,945
6,466,218
57
SalariesAndWagesGasCustomerServiceAndInformational
Customer Service and Informational (Total of line 35)
703,834
13,642
717,476
58
SalariesAndWagesGasSales
Sales (Total of line 36)
59
SalariesAndWagesGasAdministrativeAndGeneral
Administrative and General (Total of lines 37 and 46)
607,763
7,925,195
165,355
8,698,313
60
SalariesAndWagesGasOperationAndMaintenance
Total Operation and Maintenance (Total of lines 50 thru 59)
7,866,865
23,679,218
542,631
32,088,714
61
SalariesAndWagesOtherUtilityDepartmentsAbstract
Other Utility Departments
62
SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance
Operation and Maintenance
63
SalariesAndWagesOperationsAndMaintenance
TOTAL ALL Utility Dept. (Total of lines 25, 60, and 62)
24,904,359
75,822,540
4,312,892
105,039,791
64
SalariesAndWagesUtilityPlantAbstract
Utility Plant
65
SalariesAndWagesUtilityPlantConstructionAbstract
Construction (By Utility Departments)
66
SalariesAndWagesUtilityPlantConstructionElectricPlant
Electric Plant
24,512,008
22,927,737
47,439,745
67
SalariesAndWagesUtilityPlantConstructionGasPlant
Gas Plant
3,080,187
13,331,900
16,412,087
68
SalariesAndWagesUtilityPlantConstructionOther
Other
69
SalariesAndWagesUtilityPlantConstruction
TOTAL Construction (Total of lines 66 thru 68)
27,592,195
36,259,637
63,851,832
70
SalariesAndWagesPlantRemovalAbstract
Plant Removal (By Utility Departments)
71
SalariesAndWagesPlantRemovalElectricPlant
Electric Plant
5,210,425
2,739,025
7,949,450
72
SalariesAndWagesPlantRemovalGasPlant
Gas Plant
381,080
926,407
1,307,487
73
SalariesAndWagesPlantRemovalOther
Other
74
SalariesAndWagesPlantRemoval
TOTAL Plant Removal (Total of lines 71 thru 73)
5,591,505
3,665,432
9,256,937
75.1
Other Accounts (Specify) (footnote details)
(a)
10,527,365
(b)
15,972,670
5,445,305
76
TOTAL Other Accounts
10,527,365
15,972,670
5,445,305
77
TOTAL SALARIES AND WAGES
47,560,694
131,720,279
4,312,892
183,593,865


Name of Respondent:


Duke Energy Ohio, Inc.
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

 

Projects For Duke's Subsidiaries & Merchandising

 

$ 68,555

Other Work in Progress

 

(12,303,672)

Other Accounts

 

1,707,752

Total

 

$ (10,527,365)

(b) Concept: SalariesAndWagesOtherAccounts

 

Projects For Duke's Subsidiaries & Merchandising

 

$ 223,937

Other Work in Progress

 

13,035,830

Other Accounts

 

2,712,903

Total

 

$ 15,972,670


Name of Respondent:

Duke Energy Ohio, Inc.
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
ACCENTURE LLP - CONSULTING - FINANCE, IT
1,798,425
2
K&L GATES LLP - LEGAL SERVICES
1,167,385
3
INTERNATIONAL BUSINESS MAHCINES CORP - CONSULTING - IT
714,686
4
METRO CONSULTING ASSOCIATES LLC - CONSULTING - ENGINEERING
685,752
5
RUBICON ASSOCIATES LLC - CONSULTING - FINANCE
621,810
6
ELECTRIC POWER RESEARCH INSTITUTE EPRI - CONSULTING - ENERGY
462,978
7
EFFICIENCY
8
FROST BROWN TODD LLC - LEGAL SERVICES
420,805
9
ERNST & YOUNG LLP - CONSULTING - REGULATORY
283,653
10
OTHER
4,209,245
11
TOTAL
10,364,739
12
TOTAL


Name of Respondent:

Duke Energy Ohio, Inc.
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
(a)
Services Provided by Duke Energy Business Services
Duke Energy Business Services, LLC
556,899,138
3
Customer & Market Services
Duke Energy Carolinas, LLC
20,819,469
4
Generation Services
Duke Energy Carolinas, LLC
279,585
5
Other Goods and Services
Duke Energy Carolinas, LLC
886,814
6
Transmission and Distribution Services
Duke Energy Carolinas, LLC
7,578,593
7
Customer & Market Services
Duke Energy Progress, LLC
1,208,586
8
Generation Services
Duke Energy Progress, LLC
180,204
9
Other Goods and Services
Duke Energy Progress, LLC
120,550
10
Transmission and Distribution Services
Duke Energy Progress, LLC
2,166,108
11
Customer & Market Services
Duke Energy Florida, LLC
179,493
12
Generation Services
Duke Energy Florida, LLC
7,159
13
Other Goods and Services
Duke Energy Florida, LLC
15,873
14
Transmission and Distribution Services
Duke Energy Florida, LLC
355,201
15
Customer & Market Services
Duke Energy Indiana, LLC
266,276
16
Generation Services
Duke Energy Indiana, LLC
1,256
17
Other Goods and Services
Duke Energy Indiana, LLC
4,899
18
Transmission and Distribution Services
Duke Energy Indiana, LLC
6,641,220
19
Customer & Market Services
Duke Energy Kentucky, Inc.
564,301
20
Gas Distribution Services
Duke Energy Kentucky, Inc.
1,202,008
21
Generation Services
Duke Energy Kentucky, Inc.
22
Other Goods and Services
Duke Energy Kentucky, Inc.
25,000
23
Transmission and Distribution Services
Duke Energy Kentucky, Inc.
3,734,066
24
Gas Distribution Services
Piedmont Natural Gas Company, Inc.
3,386,669
25
Customer & Market Services
Piedmont Natural Gas Company, Inc.
26
Transmission and Distribution Services
Piedmont Natural Gas Company, Inc.
19
TOTAL
20
Goods or Services Provided for Affiliated Company
21
Services Provided to Duke Energy Business Services
Duke Energy Business Services, LLC
11,358,645
22
Customer & Market Services
Duke Energy Carolinas, LLC
212,730
23
Gas Distribution Services
Duke Energy Carolinas, LLC
902
24
Other Goods and Services
Duke Energy Carolinas, LLC
394,965
25
Transmission and Distribution Services
Duke Energy Carolinas, LLC
1,826,191
26
Customer & Market Services
Duke Energy Progress, LLC
182,481
27
Gas Distribution Services
Duke Energy Progress, LLC
6,893
28
Other Goods and Services
Duke Energy Progress, LLC
281,489
29
Transmission and Distribution Services
Duke Energy Progress, LLC
2,103,113
30
Customer & Market Services
Duke Energy Florida, LLC
22,243
31
Gas Distribution Services
Duke Energy Florida, LLC
5,194
32
Other Goods and Services
Duke Energy Florida, LLC
147,040
33
Transmission and Distribution Services
Duke Energy Florida, LLC
486,487
34
Generation Services
Duke Energy Kentucky, Inc.
35
Customer & Market Services
Duke Energy Kentucky, Inc.
2,118,446
36
Gas Distribution Services
Duke Energy Kentucky, Inc.
6,503,161
37
Other Goods and Services
Duke Energy Kentucky, Inc.
5,018
38
Transmission and Distribution Services
Duke Energy Kentucky, Inc.
8,784,657
39
Customer & Market Services
Duke Energy Indiana, LLC
2,748,415
40
Gas Distribution Services
Duke Energy Indiana, LLC
4,147
41
Other Goods and Services
Duke Energy Indiana, LLC
6,710,646
42
Transmission and Distribution Services
Duke Energy Indiana, LLC
7,715,574
43
Customer & Market Services
Piedmont Natural Gas Company, Inc.
44
Gas Distribution Services
Piedmont Natural Gas Company, Inc.
234,322
45
Other Goods and Services
Piedmont Natural Gas Company, Inc.
99,955
46
Transmission and Distribution Services
Piedmont Natural Gas Company, Inc.
47
Other Goods and Services
KO Transmission Company
28,925,488
40
TOTAL


Name of Respondent:

Duke Energy Ohio, Inc.
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

When an employee of the Service Company performs services for a Client Company, costs will be directly assigned or distributed or allocated. For allocated services, the allocation method will be on a basis reasonably related to the service performed. The Service Company Utility Service Agreement prescribes 23 Service Company functions and approximately 20 allocation methods.

 

Functions and Allocation Methods:

Information Systems

  • Number of Central Processing Unit Seconds Ratio/Millions of Instructions per Second

  • Number of Personal Computer Workstations Ratio

  • Number of Information Systems Servers Ratio

  • Number of Employees Ratio

Meters

  • Number of Customers Ratio

Transportation

  • Number of Employees Ratio

  • Three Factor Formula

Electric System Maintenance

  • Circuit Miles of Electric Transmission Lines Ratio

  • Circuit Miles of Electric Distribution Lines Ratio

Marketing and Customer Relations and Grid Solutions

  • Number of Customers Ratio

Electric Transmission & Distribution Engineering & Construction

  • Electric Transmission Plant's Construction - Expenditures Ratio

  • Electric Distribution Plant's Construction - Expenditures Ratio

Power Engineering & Construction

  • Electric Production Plant's Construction - Expenditures Ratio

Human Resources

  • Number of Employees Ratio

Supply Chain

  • Procurement Spending Ratio

  • Inventory Ratio

Facilities

  • Square Footage Ratio

Accounting

  • Three Factor Formula

  • Generating Unit MW Capability Ratio

Power Planning and Operations

  • Electric Peak Load Ratio

  • Weighted Avg of the Circuit Miles of Electric Distribution Lines Ratio and the Electric Peak Load Ratio

  • Sales Ratio

  • Weighted Avg of the Circuit Miles of Electric Transmission Lines Ratio and the Electric Peak Load Ratio

  • Generating Unit MW Capability Ratio

Public Affairs

  • Three Factor Formula

  • Weighted Avg of Number of Customers Ratio and Number of Employees Ratio

Legal

  • Three Factor Formula

Rates

  • Sales Ratio

Finance

  • Three Factor Formula

Rights of Way

  • Circuit Miles of Electric Transmission Lines Ratio

  • Circuit Miles of Electric Distribution Lines Ratio

  • Electric Peak Load Ratio

Internal Auditing

  • Three Factor Formula

Environmental, Health and Safety

  • Three Factor Formula

  • Sales Ratio

Fuels

  • Sales Ratio

Investor Relations

  • Three Factor Formula

Planning

  • Three Factor Formula

Executive

  • Three Factor Formula

 


Name of Respondent:

Duke Energy Ohio, Inc.
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
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:


Duke Energy Ohio, Inc.
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
3
February
4
March
5
April
6
May
7
June
8
July
9
August
10
September
11
October
12
November
13
December
14
TOTAL (Total of lines 2 thru 13)
15
Gas Withdrawn from Storage
16
January
17
February
18
March
19
April
20
May
21
June
22
July
23
August
24
September
25
October
26
November
27
December
28
TOTAL (Total of lines 16 thru 27)


Name of Respondent:

Duke Energy Ohio, Inc.
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
GasInReservoirCushionGasIncludingNativeGas
Cushion Gas (Including Native Gas)
3
GasInReservoir
Total Gas in Reservoir (Total of line 1 and 2)
4
CertificatedStorageCapacity
Certificated Storage Capacity
5
NumberOfInjectionWithdrawalWells
Number of Injection - Withdrawal Wells
6
NumberOfObservationWells
Number of Observation Wells
7
MaximumDaysWithdrawalFromStorage
Maximum Days' Withdrawal from Storage
8
DateOfMaximumDaysWithdrawal
Date of Maximum Days' Withdrawal
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:

Duke Energy Ohio, Inc.
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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
25
TOTAL


Name of Respondent:

Duke Energy Ohio, Inc.
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
OtherFirmTransportationVolumesOfGasTransported
Other Firm Transportation
5
InterruptibleTransportationVolumesOfGasTransported
Interruptible Transportation
6
Other (Specify)
6.1
7
TOTAL
8
Volumes of gas Withdrawn form Storage under Storage Contract
9
NoNoticeStorageVolumesOfGasWithdrawnFromStorageUnderStorageContract
No-Notice Storage
10
OtherFirmStorageVolumesOfGasWithdrawnFromStorageUnderStorageContract
Other Firm Storage
11
InterruptibleStorageVolumesOfGasWithdrawnFromStorageUnderStorageContract
Interruptible Storage
12
Other (Specify)
12.1
13
TOTAL
14
Other Operational Activities
15
GasWithdrawnFromStorageForSystemOperationsOtherOperationalActivities
Gas Withdrawn from Storage for System Operations
16
ReductionInLinePackOtherOperationalActivities
Reduction in Line Pack
17
Other (Specify)
17.1
18
TOTAL
19
SECTION B: CONSECUTIVE THREE_DAY PEAK DELIVERIES
20
Date(s):
22
NoNoticeTransportationVolumesOfGasTransported
No-Notice Transportation
23
OtherFirmTransportationVolumesOfGasTransported
Other Firm Transportation
24
InterruptibleTransportationVolumesOfGasTransported
Interruptible Transportation
25
Other (Specify)
25.1
26
TOTAL
27
Volumes of gas Withdrawn form Storage under Storage Contract
28
NoNoticeStorageVolumesOfGasWithdrawnFromStorageUnderStorageContract
No-Notice Storage
29
OtherFirmStorageVolumesOfGasWithdrawnFromStorageUnderStorageContract
Other Firm Storage
30
InterruptibleStorageVolumesOfGasWithdrawnFromStorageUnderStorageContract
Interruptible Storage
31
Other (Specify)
31.1
32
TOTAL
33
Other Operational Activities
34
GasWithdrawnFromStorageForSystemOperationsOtherOperationalActivities
Gas Withdrawn from Storage for System Operations
35
ReductionInLinePackOtherOperationalActivities
Reduction in Line Pack
36
Other (Specify)
36.1
37
TOTAL


Name of Respondent:

Duke Energy Ohio, Inc.
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
Eastern Ave - Ohio
Liquid Petroleum Gas Installation
91,000
(a)
True
2
Erlanger KY- Owned by Duke KY
Liquid Petroleum Gas Installation
44,940
(b)
True


Name of Respondent:

Duke Energy Ohio, Inc.
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: AuxiliaryPeakingFacilitiesIndicatorIfFacilityOperatedOnDayOfHighestTransmissionPeakDelivery
Original value: Y
(b) Concept: AuxiliaryPeakingFacilitiesIndicatorIfFacilityOperatedOnDayOfHighestTransmissionPeakDelivery
Original value: Y

Name of Respondent:

Duke Energy Ohio, Inc.
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)
19,081,873
4
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForGathering
Gas of Others Received for Gathering (Account 489.1)
303
5
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForTransmission
Gas of Others Received for Transmission (Account 489.2)
305
6
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForDistribution
Gas of Others Received for Distribution (Account 489.3)
301
65,538,275
7
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForContractStorage
Gas of Others Received for Contract Storage (Account 489.4)
307
8
QuantityOfNaturalGasReceivedByUtilityGasOfOthersReceivedForProductionExtractionProcessing
Gas of Others Received for Production/Extraction/Processing (Account 490 and 491)
9
QuantityOfNaturalGasReceivedByUtilityExchangedGasReceivedFromOthers
Exchanged Gas Received from Others (Account 806)
328
52,209
10
QuantityOfNaturalGasReceivedByUtilityGasReceivedAsImbalances
Gas Received as Imbalances (Account 806)
328
11
QuantityOfNaturalGasReceivedByUtilityReceiptsOfUtilitysGasTransportedByOthers
Receipts of Respondent's Gas Transported by Others (Account 858)
332
12
QuantityOfNaturalGasReceivedByUtilityOtherGasWithdrawnFromStorage
Other Gas Withdrawn from Storage (Explain)
13
QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsCompressorStationFuel
Gas Received from Shippers as Compressor Station Fuel
14
QuantityOfNaturalGasReceivedByUtilityGasReceivedFromShippersAsLostAndUnaccountedFor
Gas Received from Shippers as Lost and Unaccounted for
15
QuantityOfNaturalGasReceivedByUtilityOther
Other Receipts (Specify) (footnote details)
138,183
15.1
QuantityOfNaturalGasReceivedByUtilityOther
Other Receipts (Specify) (footnote details)
16
QuantityOfNaturalGasReceivedByUtility
Total Receipts (Total of lines 3 thru 15)
84,706,122
17
QuantityOfNaturalGasDeliveredByUtilityAbstract
GAS DELIVERED
18
QuantityOfNaturalGasDeliveredByUtilityGasSales
Gas Sales (Accounts 480-484)
18,705,822
19
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasGatheredForOthers
Deliveries of Gas Gathered for Others (Account 489.1)
303
20
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasTransportedForOthers
Deliveries of Gas Transported for Others (Account 489.2)
305
21
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasDistributedForOthers
Deliveries of Gas Distributed for Others (Account 489.3)
301
63,115,661
22
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfContractStorageGas
Deliveries of Contract Storage Gas (Account 489.4)
307
23
QuantityOfNaturalGasDeliveredByUtilityGasOfOthersDeliveredForProductionExtractionProcessing
Gas of Others Delivered for Production/Extraction/Processing (Account 490 and 491)
24
QuantityOfNaturalGasDeliveredByUtilityExchangeGasDeliveredToOthers
Exchange Gas Delivered to Others (Account 806)
328
52,209
25
QuantityOfNaturalGasDeliveredByUtilityGasDeliveredAsImbalances
Gas Delivered as Imbalances (Account 806)
328
26
QuantityOfNaturalGasDeliveredByUtilityDeliveriesOfGasToOthersForTransportation
Deliveries of Gas to Others for Transportation (Account 858)
332
27
QuantityOfNaturalGasDeliveredByUtilityOtherGasDeliveredToStorage
Other Gas Delivered to Storage (Explain)
28
QuantityOfNaturalGasDeliveredByUtilityGasUsedForCompressorStationFuel
Gas Used for Compressor Station Fuel
509
29
GasUsedForOtherDeliveriesAndGasUsedForOtherOperations
Other Deliveries and Gas Used for Other Operations
33,682
29.1
GasUsedForOtherDeliveriesAndGasUsedForOtherOperations
Other Deliveries and Gas Used for Other Operations
30
QuantityOfNaturalGasDeliveredByUtility
Total Deliveries (Total of lines 18 thru 29)
81,802,956
31
GasLossesAndGasUnaccountedForGasAccountAbstract
GAS LOSSES AND GAS UNACCOUNTED FOR
32
GasAccountGasLossesAndGasUnaccountedForGasAccount
Gas Losses and Gas Unaccounted For
2,903,166
33
DeliveriesGasLossesAndUnaccountedForGasAccountAbstract
TOTALS
34
DeliveriesGasLossesAndUnaccountedForGasAccount
Total Deliveries, Gas Losses & Unaccounted For (Total of lines 30 and 32)
84,706,122


Name of Respondent:

Duke Energy Ohio, Inc.
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
5
Distribution
6
Storage
7
Total Shipper Supplied Gas
LESS GAS USED FOR COMPRESSOR STATION FUEL (LINE 28, PAGE 520)
9
Gathering
10
Production/Extraction/Processing
11
Transmission
12
Distribution
13
Storage
14
Total gas used in compressors
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
19
Distribution
20
Storage
21
Other Deliveries (specify) (footnote details)
22
Total Gas Used For Other Deliveries And Gas Used For Other Operations
23
LESS GAS LOST AND UNACCOUNTED FOR (LINE 32, PAGE 520)
24
Gathering
25
Production/Extraction/Processing
26
Transmission
27
Distribution
28
Storage
29
Other Deliveries (specify) (footnote details)
30
Total Gas Lost And Unaccounted For
30.1
NET EXCESS OR (DEFICIENCY)
31
Other Losses
32
Gathering
33
Production/Extraction/Processing
34
Transmission
35
Distribution
36
Storage
37
Total Net Excess Or (Deficiency)
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
55.2
55.3
55.4
55.5
55.6
55.7
55.8
55.9
55.10
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
67
Backhaul Volume in Dths for the Quarter
68
TOTAL (Lines 66 and 67)


Name of Respondent:

Duke Energy Ohio, Inc.
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
5
Distribution
6
Storage
7
Total Shipper Supplied Gas
8
LESS GAS USED FOR COMPRESSOR STATION FUEL (LINE 28, PAGE 520)
9
Gathering
10
Production/Extraction/Processing
11
Transmission
12
Distribution
13
Storage
14
Total gas used in compressors
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
19
Distribution
20
Storage
21
Other Deliveries (specify) (footnote details)
22
Total Gas Used For Other Deliveries And Gas Used For Other Operations
23
LESS GAS LOST AND UNACCOUNTED FOR (LINE 32, PAGE 520)
24
Gathering
25
Production/Extraction/Processing
26
Transmission
27
Distribution
28
Storage
29
Other Deliveries (specify) (footnote details)
30
Total Gas Lost And Unaccounted For
30.1
NET EXCESS OR (DEFICIENCY)
31
Other Losses
32
Gathering
33
Production/Extraction/Processing
34
Transmission
35
Distribution
36
Storage
37
Total Net Excess Or (Deficiency)
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
55.2
55.3
55.4
55.5
55.6
55.7
55.8
55.9
55.10
65
Total Gas Acquired To Meet Deficiency


Name of Respondent:

Duke Energy Ohio, Inc.
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
5
Distribution
6
Storage
7
Total Shipper Supplied Gas
8
LESS GAS USED FOR COMPRESSOR STATION FUEL (LINE 28, PAGE 520)
9
Gathering
10
Production/Extraction/Processing
11
Transmission
12
Distribution
13
Storage
14
Total gas used in compressors
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
19
Distribution
20
Storage
21
Other Deliveries (specify) (footnote details)
22
Total Gas Used For Other Deliveries And Gas Used For Other Operations
23
LESS GAS LOST AND UNACCOUNTED FOR (LINE 32, PAGE 520)
24
Gathering
25
Production/Extraction/Processing
26
Transmission
27
Distribution
28
Storage
29
Other Deliveries (specify) (footnote details)
30
Total Gas Lost And Unaccounted For
30.1
NET EXCESS OR (DEFICIENCY)
31
Other Losses
32
Gathering
33
Production/Extraction/Processing
34
Transmission
35
Distribution
36
Storage
37
Total Net Excess Or (Deficiency)
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
55.2
55.3
55.4
55.5
55.6
55.7
55.8
55.9
55.10
65
Total Gas Acquired To Meet Deficiency


Name of Respondent:

Duke Energy Ohio, Inc.
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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